Harvest Oil & Gas (HRST) 10-K 3 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Document Documentand Entity Information [Abstract]	'	'	'
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	'evep	'	'
Entity Registrant Name	'EV Energy Partners, LP	'	'
Entity Central Index Key	'0001361937	'	'
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	'	48,572,019	'
Entity Public Float	'	'	$1,444,467,804

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$11,698	$7,486
Accounts receivable:	'	'
Oil, natural gas and natural gas liquids revenues	37,661	34,909
Related party	2,873	1,422
Other	1,111	11,263
Derivative asset	13,543	40,771
Other current assets	6,916	1,750
Assets held for sale	8,012	'
Total current assets	81,814	97,601
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2013, $569,770; December 31, 2012, $389,206	1,829,062	1,875,890
Other property, net of accumulated depreciation and amortization; December 31, 2013, $754; December 31, 2012, $598	1,259	1,325
Long-term derivative asset	29,088	45,839
Investments in unconsolidated affiliates	254,978	34,545
Other assets	8,782	10,214
Total assets	2,204,983	2,065,414
Current liabilities:	'	'
Accounts payable and accrued liabilities	46,876	40,171
Derivative liability	3,348	'
Liabilities related to assets held for sale	2,155	'
Total current liabilities	52,379	40,171
Asset retirement obligations	99,133	102,707
Long-term debt	980,297	859,218
Other long-term liabilities	1,241	3,494
Commitments and contingencies	'	'
Owners' equity:	'	'
General partner interest	-11,785	-12,351
Total owners' equity	1,071,933	1,059,824
Total liabilities and owners' equity	2,204,983	2,065,414
Common Unitholders [Member]	'	'
Owners' equity:	'	'
Common unitholders - 48,349,080 units and 42,320,707 units issued and outstanding as of December 31, 2013 and 2012, respectively	$1,083,718	$1,072,175

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Oil and natural gas properties, accumulated depreciation, depletion and amortization	$569,770	$389,206
Other property, accumulated depreciation and amortization	$754	$598
Common Unitholders [Member]	'	'
Common unitholders, units issued	48,349,080	42,320,707
Common unitholders, units outstanding	48,349,080	42,320,707

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:	'	'	'
Oil, natural gas and natural gas liquids revenues	$310,883	$281,749	$256,370
Transportation and marketing-related revenues	4,429	3,731	5,470
Total revenues	315,312	285,480	261,840
Operating costs and expenses:	'	'	'
Lease operating expenses	104,465	103,605	74,419
Cost of purchased natural gas	3,242	2,600	4,078
Dry hole and exploration costs	2,380	6,771	12,140
Production taxes	11,476	10,911	11,247
Asset retirement obligations accretion expense	4,925	5,116	3,914
Depreciation, depletion and amortization	113,818	113,381	74,723
General and administrative expenses	40,677	42,682	34,968
Impairment of oil and natural gas properties	85,341	34,453	11,037
Gain on sales of oil and natural gas properties	-41,309	'	-4,017
Total operating costs and expenses	325,015	319,519	222,509
Operating (loss) income	-9,703	-34,039	39,331
Other income (expense), net:	'	'	'
(Loss) gain on derivatives, net	-17,262	66,734	93,907
Interest expense	-49,062	-48,689	-30,568
Other income, net	277	705	325
Total other (expense) income, net	-66,047	18,750	63,664
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	-75,750	-15,289	102,995
Income taxes	-133	-1,078	-354
(Loss) income before equity in (loss) income of unconsolidated affiliates	-75,883	-16,367	102,641
Equity in (loss) income of unconsolidated affiliates	-344	18	'
Net (loss) income	-76,227	-16,349	102,641
Limited partners' interest in net (loss) income	($76,708)	($16,022)	$91,755
Net (loss) income per limited partner unit:	'	'	'
Basic	($1.76)	($0.38)	$2.71
Diluted	($1.76)	($0.38)	$2.68
Weighted average limited partner units outstanding:	'	'	'
Basic	43,691	41,952	33,895
Diluted	43,691	41,952	34,183

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 (loss) income	($76,227)	($16,349)	$102,641
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:	'	'	'
Dry hole costs	616	1,100	9,220
Asset retirement obligations accretion expense	4,925	5,116	3,914
Depreciation, depletion and amortization	113,818	113,381	74,723
Equity-based compensation	17,470	16,433	9,834
Impairment of oil and natural gas properties	85,341	34,453	11,037
Gain on sales of oil and natural gas properties	-41,309	'	-4,017
Loss (gain) on derivatives, net	17,262	-66,734	-93,907
Cash settlements of matured derivative contracts	30,066	114,343	52,416
Amortization of deferred loan costs	2,333	2,183	1,348
Equity in loss (income) of unconsolidated affiliates	344	-18	'
Distributions from unconsolidated affiliates	285	79	'
Other	-296	2,165	563
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-2,671	-1,773	-6,505
Other current assets	-68	51	-342
Accounts payable and accrued liabilities	1,316	5,185	7,362
Other, net	-706	-100	-1,075
Net cash flows provided by operating activities	152,499	209,515	167,212
Cash flows from investing activities:	'	'	'
Acquisitions of oil and natural gas properties	-57,976	-120,033	-463,624
Additions to oil and natural gas properties	-97,946	-129,783	-75,913
Prepaid drilling costs	-5,041	'	'
Investments in unconsolidated affiliates	-221,101	-33,811	'
Proceeds from sale of oil and natural gas properties	44,056	5,522	14,012
Distributions from unconsolidated affiliates	38	19	'
Settlements from acquired derivatives	'	4,578	6,563
Net cash flows used in investing activities	-337,970	-273,508	-518,962
Cash flows from financing activities:	'	'	'
Long-term debt borrowings	329,000	160,000	477,500
Repayments of long-term debt borrowings	-208,000	-460,000	-436,500
Proceeds from debt offering	'	206,000	292,500
Loan costs paid	'	-4,152	-7,698
Proceeds from public equity offerings	204,527	262,833	147,108
Offering costs	-226	-304	-347
Contributions from general partner	4,508	5,714	3,191
Distributions paid	-140,126	-128,924	-115,101
Distribution related to acquisition	'	'	-1,718
Net cash flows provided by financing activities	189,683	41,167	358,935
Increase (decrease) in cash and cash equivalents	4,212	-22,826	7,185
Cash and cash equivalents - beginning of period	7,486	30,312	23,127
Cash and cash equivalents - end of period	$11,698	$7,486	$30,312

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Owners' Equity (USD $)	Common Unitholders [Member]	Class B Unitholders [Member]	General Partner Interest [Member]	Total
In Thousands
Balance at Dec. 31, 2010	$779,327	'	($5,380)	$773,947
Conversion of vested phantom units	3,508	'	'	3,508
Proceeds from public equity offerings, net of offering costs	146,761	'	'	146,761
Contributions from general partner	'	'	3,191	3,191
Distributions paid	-101,337	'	-13,764	-115,101
Distribution related to acquisition	'	'	-1,718	-1,718
Equity-based compensation	6,810	'	'	6,810
Net (loss) income	100,356	232	2,053	102,641
Balance at Dec. 31, 2011	935,425	232	-15,618	920,039
Conversion of vested phantom units	2,836	'	'	2,836
Proceeds from public equity offerings, net of offering costs	262,529	'	'	262,529
Contributions from general partner	'	'	5,714	5,714
Distributions paid	-114,501	-11,845	-2,578	-128,924
Equity-based compensation	12,278	1,243	458	13,979
Conversion of Class B units	-11,530	11,530	'	'
Net (loss) income	-14,862	-1,160	-327	-16,349
Balance at Dec. 31, 2012	1,072,175	'	-12,351	1,059,824
Conversion of vested phantom units	2,365	'	'	2,365
Proceeds from public equity offerings, net of offering costs	204,301	'	'	204,301
Contributions from general partner	'	'	4,508	4,508
Distributions paid	-137,363	'	-2,763	-140,126
Equity-based compensation	16,942	'	346	17,288
Net (loss) income	-74,702	'	-1,525	-76,227
Balance at Dec. 31, 2013	$1,083,718	'	($11,785)	$1,071,933

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Owners' Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statements of Changes in Owners' Equity [Abstract]	'	'	'
Conversion of vested phantom units, units	40,264	41,075	80,534
Issuance of Class B units, units	'	'	3,873,357
Proceeds from public equity offerings, offering costs	$226	$304	$347

Organization_And_Nature_Of_Bus

Organization And Nature Of Business	12 Months Ended
	Dec. 31, 2013
Organization And Nature Of Business [Abstract]	'
Organization And Nature Of Business	'
	NOTE 1. ORGANIZATION AND NATURE OF BUSINESS
	EV Energy Partners, L.P. (the “Parent”) and its wholly owned subsidiaries (collectively, the “Partnership”) are a publicly held limited partnership.  The Partnership’s general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of its general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.  EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership.  EnerVest and its affiliates also have a significant interest in the Partnership through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in the Partnership and all of its incentive distribution rights.
	The Partnership has two reportable segments: exploration and production and midstream.  The exploration and production segment is responsible for the acquisition, development and production of the Partnership’s oil and natural gas properties.  The midstream segment, which consists of the Partnership’s investments in Cardinal Gas Services, LLC (“Cardinal”) and Utica East Ohio Midstream LLC (“UEO”), is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Summary Of Significant Accounting Policies	'
	NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Basis of Presentation
	The consolidated financial statements include the operations of the Partnership and all of its wholly–owned subsidiaries (“we,” “our” or “us”).  All intercompany accounts and transactions have been eliminated in consolidation.  In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.
	Use of Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances.  Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.  While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
	Cash and Cash Equivalents
	We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.  All of our cash and cash equivalents are maintained with several major financial institutions in the United States.  Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.
	Accounts Receivable
	Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest.  We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.
	As of December 31, 2013 and 2012, we did not have any reserves for doubtful accounts, and we did not incur any expense related to bad debts.  We do not have any off–balance sheet credit exposure related to our customers.
	Property and Depreciation
	Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting.  Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.  Lease acquisition costs are capitalized when incurred.  Capitalized costs associated with unproved properties totaled $133.8 million and $133.5 million as of December 31, 2013 and December 31, 2012, respectively.  Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain non–producing leasehold costs are expensed as incurred.  For 2013, 2012 and 2011, we recorded dry hole and exploration costs of $2.4 million, $6.8 million and $12.1 million, respectively.
	No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate.  Sales proceeds are credited to the carrying value of the properties.
	The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers.  Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold and pipeline costs.
	Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to 25 years.  We expense costs for maintenance and repairs in the period incurred.  Significant improvements and betterments are capitalized if they extend the useful life of the asset.
	Impairment of Long–Lived Assets
	We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable.  The determination of recoverability is made based upon estimated undiscounted future net cash flows.  The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset.  For 2013, 2012 and 2011, we recorded impairment charges of $76.9 million, $32.4 million and $10.4 million, respectively, related to proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 8).
	Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized.  For 2013, 2012 and 2011, we recorded leasehold impairment charges of $8.5 million, $2.1 million and $0.6 million, respectively, related to unproved oil and natural gas properties.
	Investments in Unconsolidated Affiliates
	We account for our investments in unconsolidated affiliates using the equity method of accounting.  Accordingly, we recognize our proportionate share of their earnings or losses in the period in which they are reported in their financial statements rather than in the period in which they declare a dividend.  Dividends received from these unconsolidated affiliates decrease the carrying amount of our investments.
	Asset Retirement Obligations
	An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells.  After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.  If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.
	Revenue Recognition
	Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.  We follow the sales method of accounting for natural gas revenues.  Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest.  An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production.  Under the sales method, no receivables are recorded where we have taken less than our share of production.  There were no significant gas imbalances at December 31, 2013 or 2012.
	We own and operate a network of natural gas gathering systems in the Monroe field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines.  Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.
	Income Taxes
	We are a partnership that is not taxable for federal income tax purposes.  As such, we do not directly pay federal income tax.  As appropriate, our taxable income or loss is includable in the federal income tax returns of our partners.  Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.
	We record our obligations under the Texas gross margin tax as “Income taxes” in our consolidated statement of operations.
	Net Income per Limited Partner Unit
	Our partnership agreement contains incentive distribution rights.  Accordingly, net income used in the determination of net income per limited partner unit for the current reporting period is to be reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that reporting period.  The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement.  Our partnership agreement does not allow for the distribution of undistributed earnings to the holders of the incentive distribution rights, as it limits distributions to the holders of the incentive distribution rights to available cash as defined in the partnership agreement.  Basic and diluted net income per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period.
	Derivatives
	We monitor our exposure to various business risks, including commodity price and interest rate risks, and use derivatives to manage the impact of certain of these risks.  Our policies do not permit the use of derivatives for speculative purposes.  We use energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil, natural gas and natural gas liquids.
	We have elected not to designate our derivatives as hedging instruments.  Changes in the fair value of derivatives are recorded immediately to earnings as “(Loss) gain on derivatives, net” in our consolidated statements of operations.
	Concentration of Credit Risk
	All of our derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss.  As of December 31, 2013, all of our counterparties have performed pursuant to their derivative contracts.
	Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.  We have experienced no significant credit losses on such sales in the past.
	In 2013, 2012 and 2011, no customer accounted for greater than 10% of our consolidated oil, natural gas and natural gas liquids revenues.  We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.
	Recent Accounting Standards
	In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011–11, Disclosures about Offsetting Assets and Liabilities.  This ASU affects all entities that have financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement.  ASU 2011–11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013–01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, to clarify the scope of ASU 2011–11.  The provisions of both ASU 2011–11 and ASU 2013–01 are applicable to annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods.  We adopted ASU 2011–11 and 2013–01 on January 1, 2013, and the adoption did not impact our operating results, financial position or cash flows, but did impact our disclosures on offsetting arrangements (see Note 7).
	No other new accounting pronouncements issued or effective during the year ended December 31, 2013 have had or are expected to have a material impact on our consolidated financial statements.
	Subsequent Event
	In January 2014, we closed on the sale of our assets held for sale and received proceeds of $5.8 million.
	We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.

EquityBased_Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2013
Equity-Based Compensation [Abstract]	'
Equity-Based Compensation	'
	NOTE 3. EQUITY–BASED COMPENSATION
	EV Management has a long–term incentive plan (the “Plan”) for employees, consultants and directors of EV Management and its affiliates who perform services for us.  The Plan, as amended, allows for the award of unit options, phantom units, performance units, restricted units and deferred equity rights.  As of December 31, 2013, the aggregate amount of our common units that may be awarded under the plan was 4.5 million units.  Unless earlier terminated by us or unless all units available under the Plan have been paid to participants, the Plan will terminate as of the close of business on September 20, 2016.  The compensation committee of the board of directors administers the Plan.
	Phantom Units
	Equity Awards
	We account for phantom units issued beginning in 2009 as equity awards since we have determined that these awards will likely be settled by issuing common units.  Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures.  These phantom units are subject to graded vesting over a four year period.
	We estimated the fair value of these phantom units using the Black–Scholes option pricing model.  The following assumptions were used to estimate the weighted average fair value of these phantom units for the years ended December 31:
		2013	2012	2011
	Weighted average fair value of phantom units	$31.92	$58.92	$63.87
	Expected volatility	30.78%	37.87%	36.80%
	Risk–free interest rate	0.68%	0.40%	0.40%
	Dividend yield	0.00%	0.00%	0.00%
	Expected life (years)	4	4	4
	We calculated estimated volatility using historical daily prices for two years prior to the grant date.  The risk–free interest rate was based on U.S. Treasury yield curves.  The dividend yield is not taken into account as recipients are entitled to receive all distributions underlying the phantom units.
	Activity related to these phantom units is as follows:
			Weighted Average Grant Date Fair Value per Phantom Unit
		Number of Phantom Units
	Nonvested phantom units as of December 31, 2012	840,649	$50.24
	Granted	306,300	31.92
	Vested	-199,175	42.89
	Forfeited	-25,018	54.27
	Nonvested phantom units as of December 31, 2013	922,756	$45.63
	The total grant date fair value of the phantom units vested in 2013, 2012 and 2011 was $8.5 million, $4.8 million and $2.1 million, respectively.
	We recognized compensation cost related to these phantom units of $11.9 million, $8.4 million and $4.9 million in 2013, 2012 and 2011.  These costs are included in “General and administrative expenses” in our consolidated statements of operations.
	As of December 31, 2013, there was $30.2 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.9 years.
	Liability Awards
	We accounted for phantom units issued prior to 2009 as liability awards, and the fair value of these phantom units was remeasured at the end of each reporting period based on the current market price of our common units until settlement.  Prior to settlement, compensation cost was recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date and was net of estimated forfeitures.  These phantom units were subject to graded vesting over a four year period.
	Activity related to these phantom units is as follows:
	Nonvested phantom units as of December 31, 2012	40,263
	Vested	-40,263
	Nonvested phantom units as of December 31, 2013	–
	The total fair value of the phantom units vested in 2013, 2012 and 2011 was $2.4 million, $2.8 million and $3.5 million, respectively.
	We recognized compensation cost related to these phantom units of $0.2 million, $2.5 million and $3.0 million in 2013, 2012 and 2011, respectively.  These costs are included in “General and administrative expenses” in our consolidated statements of operations.
	Performance Units
	In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates.  These performance units vest 25% each year beginning in January 2012 subject to our common units achieving certain market prices.  We accounted for the performance units as equity awards.  We estimated the fair value of 0.1 million of the performance units using the Black–Scholes option pricing model, as the market price had already been achieved for those performance units.  We estimated the fair value of the remainder of the market condition performance units using the Monte Carlo simulation model.
	The following assumptions were used to estimate the weighted average fair value of the performance units:
		2011
	Weighted average fair value of performance units	$64.07
	Expected volatility	47.99%
	Risk–free interest rate	0.56%
	Expected quarterly distribution amount	$0.76
	Expected life (years)	2.69
	We calculated estimated volatility using historical daily prices prior to the grant date.  The risk–free interest rate was based on U.S. Treasury yield curves.  The dividend yield is not taken into account as recipients are entitled to receive all distributions underlying the performance units.
	Activity related to these performance units is as follows:
			Weighted Average Grant Date Fair Value per Performance Unit
		Number of Performance Units
	Nonvested performance units as of December 31, 2012	318,500	$52.45
	Vested	-83,500	19.73
	Forfeited	-10,000	64.07
	Nonvested performance units as of December 31, 2013	225,000	$64.07
	The total grant date fair value of the performance units vested in 2013, 2012 and 2011 was $1.6 million, $1.7 million and $0.2 million, respectively.
	We recognized compensation cost related to our performance units of $5.4 million, $5.6 million and $2.0 million in 2013, 2012 and 2011, respectively.  These costs are included in “General and administrative expenses” in our consolidated statements of operations.
	As of December 31, 2013, there was $5.6 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized over a weighted average period of 1.0 year.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Acquisitions [Abstract]	'
Acquisitions	'
	NOTE 4. ACQUISITIONS
	2013
	In March 2013, we received final purchase price settlements of $8.0 million related to our August 2012 acquisition of additional working interests in acreage in Ohio.
	In November 2013, we, along with certain institutional partnerships managed by EnerVest, acquired natural gas properties in the Barnett Shale.  We acquired a 31% proportional interest in these properties for an aggregate purchase price of $66.0 million, subject to customary purchase price adjustments.  We recognized $1.4 million of oil, natural gas and natural gas liquids revenues related to these acquisitions in our consolidated statement of operations for 2013.
	We accounted for these acquisitions as business combinations.  Pro forma results of operations have not been presented as the amounts would not be material to our consolidated statements of operations.
	The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with the November 2013 acquisitions are as follows:
	Accounts receivable – related party		$
			-650
	Other current assets		57
	Proved oil and natural gas properties		60,607
	Unproved oil and natural gas properties		6,018
	Other assets		900
	Accounts payable and accrued liabilities		18
	Asset retirement obligations		-976
			$
			65,974
	The amounts included in the table above represent preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for these acquisitions.  We expect to finalize the fair values in 2014.
	2012
	In February 2012 and March 2012, we, along with certain institutional partnerships managed by EnerVest, had additional closings on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011.  We acquired a 31.63% proportional interest in these properties for an aggregate purchase price of $36.5 million, subject to customary purchase price adjustments.
	In April 2012, we received final purchase price settlements of $1.7 million related to our acquisitions of oil and natural gas properties in the Barnett Shale in December 2011.
	In May 2012, we paid a final purchase price settlement of $0.9 million related to our acquisition of oil and natural gas properties in the Mid–Continent area in November 2011.
	In August 2012, we acquired additional working interests in acreage in Ohio that we believe may be prospective for the Utica Shale for $75.2 million, after preliminary purchase price adjustments.
	In November 2012, we acquired oil and natural gas assets for $1.1 million, subject to customary purchase price adjustments.
	We accounted for these acquisitions as business combinations.  Pro forma results of operations have not been presented as the amounts would not be material to our consolidated statements of operations.
	2011
	On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments.  We recognized $1.8 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.
	On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale.  We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments.  We recognized $1.7 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.
	On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale.  We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments.  We recognized $2.2 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.
	We accounted for these acquisitions as business combinations.  The following table reflects pro forma revenues, net income and net income per limited partner unit for the year ended December 31, 2011 as if these acquisitions had taken place on January 1, 2010.  These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the period presented or that may be obtained in the future.
			2011
	Revenues		$
			350,229
	Net income		140,409
	Net income per limited partner unit:
	Basic		$3.80
	Diluted		$3.77
	In addition to the acquisitions described above, we also made the following smaller acquisitions and accounted for them as business combinations:
		·		we received final purchase price settlements totaling $4.1 million related to our September 2010 and December 2010 acquisitions of oil and natural gas properties in the Mid–Continent area and the Barnett Shale;
		·		we,  along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and
		·		we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.
	As we acquired the oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests and applied purchase accounting to the remaining interests acquired.  As a result, we recorded a deemed distribution of $1.7 million that represents the difference between the recognized fair values of the identifiable assets acquired and liabilities assumed and the amount paid for the acquisition.
	The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with all of these acquisitions are as follows:
	Accounts receivable		$
			2,698
	Other current assets		1,584
	Proved oil and natural gas properties		428,478
	Unproved oil and natural gas properties		43,947
	Other property		12
	Other assets		7,706
	Accounts payable and accrued liabilities		-523
	Asset retirement obligations		-19,855
			$
			464,047

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2013
Divestitures [Abstract]	'
Divestitures	'
	NOTE 5. DIVESTITURES
	In 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica Shale acreage in Ohio.  Through December 2013, we had closed on sales with proceeds of $44.1 million for these acres, and we expect additional closings on these acres in 2014.
	In 2012, the assets and liabilities that were held for sale as of December 31, 2011 were sold for $5.5 million.  We also sold non–core oil and natural gas wells for $0.5 million, which is recorded within accounts receivable as of December 31, 2012.
	In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total E&P USA, Inc. (“Total”), a subsidiary of Total S.A., and Chesapeake Energy Corporation, whereby Total acquired an undivided 25% interest in certain acres in the Utica Shale and agreed to fund certain future development costs.  We received $4.2 million in cash for our acres.  We continue to own working interests in these acres.  As of December 31, 2013, our portion of future development cost to be carried by Total was $9.4 million.
	In 2011, we sold oil and natural gas properties in the Mid–Continent and Central and East Texas areas for $9.8 million.

Investments_In_Unconsolidated_

Investments In Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2013
Investments In Unconsolidated Affiliates [Abstract]	'
Investments In Unconsolidated Affiliates	'
	NOTE 6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
	The most significant of our investments in unconsolidated affiliates are Cardinal and UEO.  We own 9% of Cardinal and, through December 2012, we owned 8% of UEO.  Cardinal and UEO are engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.
	In October 2012, we signed an agreement whereby we and EnerVest will dedicate production from certain of our operated acres in Ohio to the UEO facilities in exchange for the right to increase our ownership in UEO from 8% to 21%.  The increase in our ownership in UEO was subject to certain conditions being met on or before March 2013.  On December 20, 2012, such conditions were satisfied, and in January 2013, we paid $33.3 million to increase our ownership in UEO from 8% to 21%.
	Summarized combined financial information for Cardinal and UEO is as follows as of and for the years ended December 31:
		2013	2012
	Current assets	$71,153	$82,609
	Noncurrent assets	1,528,518	389,799
	Total assets	$	$
		1,599,671	472,408
	Current liabilities	$	$
		145,006	75,004
	Owner’s equity	1,454,665	397,404
	Total liabilities and owner’s equity	$	$
		1,599,671	472,408
	Revenues	$	$
		56,888	3,124
	Operating income (loss)	4,955	-1,654
	Net income (loss)	5,125	-1,568
	Although Cardinal and UEO had combined net income of $5.1 million for 2013, UEO incurred a net loss of $8.7 million and, as we own 21% of UEO, our proportionate share of UEO’s net loss was greater than our 9% proportionate share of Cardinal’s net income of $13.8 million.  Accordingly, we recognized a combined loss from Cardinal and UEO.
	As of December 31, 2013 and 2012, the excess of our investment over our equity in Cardinal and UEO is $8.2 million and $0.9 million, respectively.

Risk_Management

Risk Management	12 Months Ended
	Dec. 31, 2013
Risk Management [Abstract]	'
Risk Management	'
	NOTE 7. RISK MANAGEMENT
	Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids.  In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates.  As such, future earnings are subject to fluctuation due to changes in the market price of oil, natural gas and natural gas liquids and interest rates.  We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates.  Our policies do not permit the use of derivatives for speculative purposes.
	We have elected not to designate any of our derivatives as hedging instruments.  Accordingly, changes in the fair value of our derivatives are recorded immediately to earnings as “(Loss) gain on derivatives, net” in our consolidated statements of operations.
	As of December 31, 2013, we had entered into commodity contracts with the following terms:
			Weighted Average Fixed Price
		Hedged Volume
	Period Covered
	Oil (MBbls):
	Swaps – 2014	1,517.7	$91.19
	Swaps – 2015	730.0	90.09
	Natural Gas (MmmBtus):
	Swaps – 2014	39,712.0	4.7
	Swaps – 2015	36,317.5	4.94
	Swaps – 2016	10,980.0	4.17
	As of December 31, 2013, we had also entered into interest rate swaps with the following terms:
		Notional Amount	Floating	Fixed
	Period Covered		Rate	Rate
	January 2014 – July 2015	$	1 Month LIBOR	3.315%
		110,000
	The following table sets forth the fair values and classification of our outstanding derivatives:
				Net Amounts
				Am
			Gross Amounts	of Assets
		Gross Amounts	Offset in the	Presented in the
		of Recognized	Consolidated	Consolidated
		Assets	Balance Sheets	Balance Sheets
	Derivatives:
	As of December 31, 2013:
	Derivative asset	$	$	$
		24,950	-11,407	13,543
	Long–term derivative asset	30,903	-1,815	29,088
	Total	$	$	$
		55,853	-13,222	42,631
	As of December 31, 2012:
	Derivative asset	$	$	$
		44,173	-3,402	40,771
	Long–term derivative asset	50,692	-4,853	45,839
	Total	$	$	$
		94,865	-8,255	86,610
				Net Amounts
				Am
			Gross Amounts	of Liabilities
		Gross Amounts	Offset in the	Presented in the
		of Recognized	Consolidated	Consolidated
		Liabilities	Balance Sheets	Balance Sheets
	Derivatives:
	As of December 31, 2013:
	Derivative liability	$	$	$
		14,755	-11,407	3,348
	Long–term derivative liability	1,815	-1,815	–
	Total	$	$	$
		16,570	-13,222	3,348
	As of December 31, 2012:
	Derivative liability	$	$	$                   –
		3,402	-3,402
	Long–term derivative liability	4,853	-4,853	–
	Total	$	$	$                   –
		8,255	-8,255
	We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our consolidated balance sheets when such amounts are with the same counterparty.  In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements.  These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.
	Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable.  We could also be required to post cash collateral related to these derivatives under certain circumstances.  As of December 31, 2013 and 2012, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	NOTE 8. FAIR VALUE MEASUREMENTS
	Recurring Basis
	The following table presents the fair value hierarchy table for our net assets and liabilities that are required to be measured at fair value on a recurring basis:
			Fair Value Measurements at the End of the Reporting Period
			Quoted Prices in Active Markets for Identical Assets
			(Level 1)
				Significant Other Observable Inputs
				(Level 2)	Significant Unobservable Inputs
					(Level 3)
		Fair Value
	As of December 31, 2013:
	Assets – Commodity contracts	$	$–	$	$–
		55,853		55,853
	Liabilities:
	Commodity contracts	$	$             –	$	$             –
		11,560		11,560
	Interest rate swaps	5,010	–	5,010	–
	Total	$	$–	$	$–
		16,570		16,570
	As of December 31, 2012:
	Assets – Commodity contracts	$	$–	$	$–
		94,865		94,865
	Liabilities – Interest rate swaps	$	$–	$	$–
		8,255		8,255
	Our derivatives consist of over–the–counter (“OTC”) contracts which are not traded on a public exchange.  As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2.  We value these derivatives using the income approach using inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves.  Our estimates of fair value have been determined at discrete points in time based on relevant market data.  There were no changes in valuation techniques or related inputs in 2013.
	Nonrecurring Basis
	The following table presents the fair value hierarchy table for our net assets and liabilities that are required to be measured at fair value on a nonrecurring basis:
			Fair Value Measurements at the End of the Reporting Period
			Quoted Prices in Active Markets for Identical Assets
			(Level 1)
				Significant Other Observable Inputs
				(Level 2)	Significant Unobservable Inputs
					(Level 3)
						Total
		Fair Value				Losses
	Year ending December 31:
	2013:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		55,163			55,163	76,342
	Long–lived assets held for sale	8,012	–	8,012	–	514
		$	$          –	$	$	$
		63,175		8,012	55,163	76,856
	2012:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		34,214			34,214	31,876
	Long–lived assets held for sale	6,014	–	6,014	–	491
		$	$          –	$	$	$
		40,228		6,014	34,214	32,367
	2011:00:00
	Long–lived assets held for sale	$	$          –	$	$–	$
		15,784		15,784		10,399
	Long–lived Assets Held and Used
	In 2013, oil and natural gas properties with an aggregate carrying amount of $131.5 million were written down to their aggregate fair value of $55.2 million, resulting in an aggregate impairment charge of $76.3 million.  This impairment charge was included in earnings for 2013.  In 2012, oil and natural gas properties with an aggregate carrying amount of $66.1 million were written down to their aggregate fair value of $34.2 million, resulting in an aggregate impairment charge of $31.9  million.  This impairment charge was included in earnings for 2012.
	The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved reserves.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk–adjusted discount rates and other relevant data.
	Long–lived Assets Held for Sale
	In 2013, we incurred an impairment charge of $0.5 million to write down assets held for sale to their fair market value of $8.0 million.  This impairment charge was included in earnings for 2013.  In 2012, we incurred additional impairment charges of $0.5 million to write down assets held for sale to their fair value of $6.0 million.  These impairment charges were included in earnings for 2012.  At various times during 2011, oil and natural gas properties with an aggregate carrying amount of $26.2 million were written down to their aggregate fair value of $15.8 million, resulting in impairment charges of $10.4 million.  These impairment charges were included in earnings for 2011.
	The fair values were determined using Level 2 inputs consisting of the mutually agreed upon selling price we received upon the sale of these oil and natural gas properties.
	As of December 31, 2013, we have $8.0 million of oil and natural gas properties and $2.2 million of ARO classified as assets held for sale and liabilities held for sale, respectively in our consolidated balance sheets.
	Financial Instruments
	The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information.  Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt.  The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items.  Derivatives are recorded at fair value (see above).
	The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us.  As of December 31, 2013 and December 31, 2012, the estimated fair value of our senior notes due 2019 was $504.7 million and $531.2 million, respectively, which differs from the carrying value of $499.3 million and $499.2 million, respectively.  The fair value of the senior notes due 2019 was determined using Level 2 inputs.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Asset Retirement Obligations	'
	NOTE 9. ASSET RETIREMENT OBLIGATIONS
	The changes in the aggregate ARO are as follows:
	Balance as of December 31, 2011	$
		93,225
	Liabilities incurred and assumed in acquisitions	5,344
	Accretion expense	5,116
	Revisions in estimated cash flows	7,637
	Settlements and divestitures	-6,638
	Balance as of December 31, 2012	104,684
	Liabilities incurred and assumed in acquisitions	1,852
	Accretion expense	4,925
	Revisions in estimated cash flows	-6,704
	Settlements and divestitures	-1,584
	Balance as of December 31, 2013	$
		103,173
	As of December 31, 2013 and 2012, $1.9 million and $2.0 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our consolidated balance sheets.  In addition, as of December 31, 2013, $2.2 million of our ARO is included in “Liabilities related to assets held for sale” in our consolidated balance sheets.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Long-Term Debt	'
	NOTE 10. LONG–TERM DEBT
	Credit Facility
	As of December 31, 2013, we have a $1.0 billion credit facility that expires in April 2016.  Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties.  We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners.  We also may use up to $100.0 million of available borrowing capacity for letters of credit.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense  of no greater than 3.5 to 1.0.  As of December 31, 2013, we were in compliance with these financial covenants.
	The facility does not require any repayments of amounts outstanding until it expires in April 2016.  Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.09% and 3.53% at December 31, 2013 and 2012, respectively).
	Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves.  As of December 31, 2013, the borrowing base under the facility was $730.0 million.  The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.
	We had $481.0 million and $360.0 million outstanding under the facility at December 31, 2013 and 2012, respectively.
	8.0% Senior Notes due 2019
	On March 22, 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019 (the “Notes”).  We received net proceeds of $291.5 million, after deducting $8.5 million for underwriters’ discounts and payment of offering expenses.
	On March 13, 2012, we issued an additional $200.0 million in aggregate principal amount of the Notes at an offering price equal to 103% of par, or $206.0 million, plus $6.6 million of accrued interest from October 15, 2011 pursuant to the same indenture under which our existing $300.0 million of 8.0% senior unsecured notes due 2019 were issued.  We received proceeds of $201.9 million after deducting $4.1 million for underwriters’ discounts and payment of offering expenses.
	The Notes were issued under an indenture dated March 22, 2011, (the “Indenture”), mature April 15, 2019, and bear interest at 8.0%.  Interest is payable semi–annually beginning October 15, 2011.  The Notes are general unsecured obligations and are effectively junior in right of payment to any of our secured indebtedness to the extent of the value of the collateral securing such indebtedness.
	The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes.  Neither the Parent nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.
	The Indenture provides that, prior to April 15, 2014, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of a public or private equity offering at a redemption price of 108.0% of the principal amount redeemed, plus accrued and unpaid interest, provided that:
		·		at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after the occurrence of such redemption; and
		·		the redemption occurs within 180 days of the date of the closing of such public or private equity offering.
	On and after April 15, 2015, we may redeem all or a part of the Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes to be redeemed to the applicable redemption date, if redeemed during the twelve–month period beginning on April 15 of the years indicated below:
	Year		Percentage
	2015		104.00%
	2016		102.00%
	2017 and thereafter		100.00%
	Prior to April 15, 2015, we may redeem all or part of the Notes at a redemption price equal to the sum of:
		·		the principal amount thereof, plus
		·		the Make Whole Premium (as defined in the Indenture) at the redemption date, plus accrued and unpaid interest, if any, to the redemption date.
	The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require us to repurchase all or part of the Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
	The Indenture contains covenants that, among other things, limit our ability to: (i) pay distributions on, purchase or redeem our common units or redeem our subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of our assets; (vii) enter into intercompany agreements that restrict distributions or other payments from our restricted subsidiaries to us; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
	The aggregate carrying amount of the Notes was $499.3 million and $499.2 million at December 31, 2013 and December 31, 2012, respectively.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Commitments And Contingencies	'
	NOTE 11. COMMITMENTS AND CONTINGENCIES
	We are involved in disputes or legal actions arising in the ordinary course of business.  We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2013 and 2012.
	As of December 31, 2013, we expect our aggregate commitment to fund the construction activities for Cardinal and UEO to be between $140.0 million and $160.0 million for 2014 and 2015.
	We have entered into a firm agreement for the future transportation and processing of natural gas.  We are obligated to transport minimum daily natural gas volumes.  As of December 31, 2013, our future minimum transportation fees under this agreement are as follows for the years ended December 31:
	13
	2014	$
		618
	2015	619
	2016	618
	2017	619
	2018	618
	Thereafter	2,268
		$
		5,360

Owners_Equity

Owners' Equity	12 Months Ended
	Dec. 31, 2013
Owners' Equity [Abstract]	'
Owners' Equity	'
	NOTE 12. OWNERS’ EQUITY
	Units Outstanding
	At December 31, 2013, owner’s equity consists of 48,349,080 common units outstanding (including 4,101,541 common units held by our executive officers and directors), collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.
	Equity Offerings
	In October 2013, we closed a public offering of 5.75 million common units at an offering price of $36.86 per common unit.  We received net proceeds of $208.5 million, including a contribution of $4.2 million by our general partner to maintain its 2% interest in us.
	In February 2012, we closed a public offering of 4.025 million of our common units at an offering price of $67.95 per common unit.  We received net proceeds of $267.9 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us.
	In March 2011, we closed a public offering of 3.45 million of our common units at an offering price of $44.42 per common unit.  We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us.
	Common Units
	The common units have limited voting rights as set forth in our partnership agreement.
	Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the common units outstanding, our general partner has the right, but not the obligation, to “call” or acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market value.  Our general partner may assign this call right to any of its affiliates or to us.
	Class B Units
	In December 2011, our general partner notified us that it had made an incentive distribution rights (“IDR”) reset election as defined in our partnership agreements.  Under the IDR reset election, our general partner relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering.  The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement.  In connection with resetting the minimum quarterly and target cash distribution levels, our general partner received 3.9 million Class B units.  In December 2012, we issued 3.9 million common units when the holders of our Class B units elected to convert their Class B units into common units on a one–for–one basis.
	The Class B units had limited voting rights as set forth in our partnership agreement.  Prior to converting into common units, each Class B unit was entitled to the same distributions and voting rights as a common unit.
	General Partner Interest
	Our general partner owns a 2% interest in us.  This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions.  Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Class B unitholders and general partner will receive.
	The general partner has the management rights as set forth in our partnership agreement.
	Allocations of Net Income
	Net income is allocated between our general partner and the limited partners in accordance with the provisions of our partnership agreement.  Net income is generally allocated first to our general partner and the limited partners in an amount equal to the net losses allocated to our general partner and the limited partners in the current and prior tax years under the partnership agreement.  The remaining net income is allocated to our general partner and the limited partners in accordance with their respective percentage interests of the general partner and limited partners.
	Cash Distributions
	We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.  Our credit facility prohibits us from making cash distributions if any default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.
	Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date.  The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, to comply with applicable laws, any of our debt instruments, or other agreements or to provide funds for distributions to unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.  Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
	Our partnership agreement requires that we make distributions of available cash from operating surplus in the following manner:
		·		first, 98% to the unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and
		·		thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.
	Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
					Marginal Percentage Interest in Distributions
			Total Quarterly Distributions Target Amount		Limited Partner	General Partner
	Minimum quarterly distribution		$0.76		98%	2%
	First target distribution		Up to $0.875725		98%	2%
	Second target distribution		Above $0.875725, up to $0.951875		85%	15%
	Thereafter		Above $0.951875		75%	25%
	The following sets forth the distributions we paid during the years ended December 31, 2013 and 2012:
					Distribution per Unit	Total Distribution
	Date Paid		Period Covered
	14-Feb-13		October 1, 2012 – December 31, 2012		$	$
					0.767	33,838
	15-May-13		January 1, 2013 – March 31, 2013		0.768	33,883
	14-Aug-13		April 1, 2013 – June 30, 2013		0.769	33,925
	14-Nov-13		July 1, 2013 – September 30, 2013		0.770	38,480
						$
						140,126
	14-Feb-12		October 1, 2011 – December 31, 2011		$	$
					0.763	29,815
	15-May-12		January 1, 2012 – March 31, 2012		0.764	32,994
	August 14 2012		April 1, 2012 – June 30, 2012		0.765	33,036
	14-Nov-12		July 1, 2012 – September 30, 2012		0.766	33,079
						$
						128,924
	On January 31, 2014, the board of directors of EV Management declared a $0.771 per unit distribution for the fourth quarter of 2013 on all common units.  The distribution was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.  The aggregate amount of the distribution was $38.7 million.

Net_Loss_Income_Per_Limited_Pa

Net (Loss) Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2013
Net (Loss) Income Per Limited Partner Unit [Abstract]	'
Net (Loss) Income Per Limited Partner Unit	'
	NOTE 13. NET (LOSS) INCOME PER LIMITED PARTNER UNIT
	The following sets forth the calculation of net (loss) income per limited partner unit for the years ended December 31:
		2013	2012	2011
	Net (loss) income	$	$	$
		-76,227	-16,349	102,641
	Incentive distribution rights	–	–	-8,833
	General partner’s 2% interest in net (loss) income	1,525	327	-2,053
	Net (loss) income attributable to participating securities	-2,006	–	–
	Limited partners’ interest in net (loss) income	$	$	$
		-76,708	-16,022	91,755
	Weighted average limited partner units outstanding:
	Common units	43,691	38,156	33,532
	Class B units	–	3,662	212
	Performance units	–	134	151
	Denominator for basic net (loss) income per limited partner unit	43,691	41,952	33,895
	Dilutive phantom units (1)	–	–	288
	Total	43,691	41,952	34,183
	Net (loss) income per limited partner unit:
	Basic	($1.76)	($0.38)	$2.71
	Diluted	($1.76)	($0.38)	$2.68
	_____________
	(1)Units totaling 0.2 million and 0.8 million units were not included in the computation of diluted net (loss) income per limited partner unit for 2013 and 2012, respectively, because the effect would have been anti-dilutive.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	NOTE 14. RELATED PARTY TRANSACTIONS
	Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $10.0 million, $13.1 million and $10.9 million in 2013, 2012 and 2011, respectively, in monthly administrative fees for providing us general and administrative services.  These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.  These fees are included in general and administrative expenses in our consolidated statements of operations.
	We have entered into operating agreements with EnerVest whereby a subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest.  During 2013, 2012 and 2011, we reimbursed EnerVest approximately $17.1 million, $17.5 million and $15.5 million, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties.  As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis.  These costs are included in lease operating expenses in our consolidated statements of operations.  Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil, natural gas and natural gas liquids sales and distributes them to us and other working interest owners.
	In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from certain acres in Ohio (the "Underlying Properties"), which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership.  EnerVest is the general partner of this partnership.  The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties.  We own a 48% limited partner interest in the partnership and account for our investment using the equity method of accounting.  We recognized $0.2 million and $0.1 million of income from unconsolidated affiliates in 2013 and 2012, respectively, and we received $0.2 million of distributions in 2013.
	In August 2011, followed by a second closing in October 2011, we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million (see Note 4).

Other_Supplemental_Information

Other Supplemental Information	12 Months Ended
	Dec. 31, 2013
Other Supplemental Information [Abstract]	'
Other Supplemental Information	'
	NOTE 15. OTHER SUPPLEMENTAL INFORMATION
	Supplemental cash flows and non–cash transactions were as follows as of and for the years ended December 31:
		2013	2012	2011
	Supplemental cash flows information:
	Cash paid for interest, net of capitalized interest of $7,276 and $906 at December 31, 2013 and 2012, respectively	$	$	$
		45,355	47,903	21,880
	Cash paid for income taxes	325	340	265
	Non–cash transactions:
	Costs for additions to oil and natural gas properties in         accounts payable and accrued liabilities	19,450	13,951	12,046
	Purchase price adjustment in accounts receivable	–	7,969	–
	Cost for acquisition of oil and natural gas properties in accounts payable and accrued liabilities			423
		–	–
	Accounts payable and accrued liabilities consisted of the following as of December 31:
		2013	2012
	Costs for additions to oil and natural gas properties	$	$13,951
		19,450
	Lease operating expenses	7,793	7,309
	Interest	8,701	8,566
	Production and ad valorem taxes	4,862	4,379
	General and administrative expenses	2,082	2,596
	Current portion of ARO	1,885	1,977
	Derivative settlements	1,443	364
	Other	660	1,029
	Total	$	$
		46,876	40,171

Quarterly_Data

Quarterly Data	12 Months Ended
	Dec. 31, 2013
Quarterly Data [Abstract]	'
Quarterly Data	'
	NOTE 16. QUARTERLY DATA (UNAUDITED)
		First	Second Quarter	Third	Fourth Quarter
		Quarter		Quarter
	2013
	Revenues	$	$	$	$
		73,702	81,602	81,414	78,594
	Gross profit (1)	43,949	51,510	51,526	49,144
	Net (loss) income	-46,581	32,854	-12,314	-50,186
	Net (loss) income per limited partner unit:
	Basic	($1.08)	$0.74	($0.29)	($1.06)
	Diluted	($1.08)	$0.74	($0.29)	($1.06)
	2012
	Revenues	$	$	$	$
		77,731	63,552	68,701	75,496
	Gross profit (1)	45,204	35,676	40,631	46,853
	Net income (loss)	28,593	14,956	-50,019	-9,879
	Net income (loss) per limited partner unit:
	Basic	$0.69	$0.35	($1.15)	($0.23)
	Diluted	$0.69	$0.34	($1.15)	($0.23)
	_____________
	(1)Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	NOTE 17. SEGMENT INFORMATION
	As a result of our decision to allocate resources to our midstream business, we now have two reportable segments: exploration and production and midstream.  Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties.  Our midstream segment, which consists of Cardinal and UEO, is accounted for using the equity method of accounting and is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.  All of our operations are located in the United States.
	Management evaluates the performance of our segments based on segment profits, which include segment revenues and direct segment costs and expenses.  Segment profit excludes items such as asset retirement obligations accretion expense, depreciation, depletion and amortization, general and administrative expenses, impairment of oil and natural gas properties, (loss) gain on derivatives, interest expense and other income or expense.
	We have not presented any segment information for 2011 as we did not begin investing in Cardinal and UEO until 2012.
	Summarized financial information for our operating segments is shown below:
		Exploration and Production
				Consolidated
			Midstream	Total
	Year ended December 31, 2013:
	Total revenues	$	$             –	$
		315,312		315,312
	Segment profit	193,749	–	193,749
	Equity in (loss) income of unconsolidated affiliates	259	-603	-344
	Year ended December 31, 2012:
	Total revenues	285,480	–	285,480
	Segment profit	161,593	–	161,593
	Equity in (loss) income of unconsolidated affiliates	156	-138	18
	As of December 31, 2013:
	Capital expenditures	175,870	–	175,870
	Total assets	1,950,300	254,683	2,204,983
	As of December 31, 2012:
	Capital expenditures	249,048	–	249,048
	Total assets	2,031,228	34,186	2,065,414
	The following table reconciles the segment profits reported above to loss before income taxes and (loss) income from unconsolidated affiliates for the years ended December 31:
		2013	2012
	Segment profit	$	$
		193,749	161,593
	Asset retirement obligations accretion expense	-4,925	-5,116
	Depreciation, depletion and amortization	-113,818	-113,381
	General and administrative expenses	-40,677	-42,682
	Impairment of oil and natural gas properties	-85,341	-34,453
	Gain on sales of oil and natural gas properties	41,309	–
	(Loss) gain on derivatives, net	-17,262	66,734
	Interest expense	-49,062	-48,689
	Other income	277	705
	Loss before income taxes and equity in (loss) income from unconsolidated affiliates	$	$
		-75,750	-15,289

Supplementary_Information_On_O

Supplementary Information On Oil And Natural Gas Activities	12 Months Ended
	Dec. 31, 2013
Supplementary Information On Oil And Natural Gas Activities [Abstract]	'
Supplementary Information On Oil And Natural Gas Activities	'
	NOTE 18. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)
	Capitalized costs relating to oil and natural gas producing activities are as follows at December 31:
		2013	2012
	Proved oil and natural gas properties	$	$
		2,265,069	2,131,616
	Unproved oil and natural gas properties	133,763	133,480
		2,398,832	2,265,096
	Accumulated depreciation, depletion and amortization	-569,770	-389,206
	Net capitalized costs	$	$
		1,829,062	1,875,890
	Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:
		2013	2012	2011
	Acquisition of oil and natural gas properties:
	Proved	$	$	$
		59,602	36,834	408,633
	Unproved	6,018	75,229	43,947
	Exploration costs	1,764	5,671	6,112
	Development costs	108,486	131,674	77,961
	Total	$	$	$
		175,870	249,408	536,653

Estimated_Proved_Oil_Natural_G

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves	12 Months Ended
	Dec. 31, 2013
Estimated Proved Oil, Natural Gas And Natural Liquids Reserves [Abstract]	'
Estimated Proved Oil, Natural Gas And Natural Liquids Reserves	'
	NOTE 19. ESTIMATED PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)
	Our estimated proved reserves are all located within the United States.  We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures.  Accordingly, these estimates are expected to change as further information becomes available.  Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and natural gas liquids reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates.  The estimates of our proved reserves as of December 31, 2013, 2012 and 2011 have been prepared by Cawley, Gillespie, & Associates, Inc., independent petroleum consultants.
	The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.
				Natural Gas Liquids
		Oil	Natural Gas	(MBbls) (1)
		(MBbls) (1)	(Mmcf) (2)		MMcfe (3)
	Proved developed and undeveloped reserves:
	As of December 31, 2010	12,888	575,202	27,468	817,340
	Revisions of previous estimates	718	-20,204	-123	-16,631
	Purchases of minerals in place	2,506	277,595	14,405	379,060
	Extensions and discoveries	595	6,352	319	11,839
	Production	-891	-29,247	-1,096	-41,169
	Sales of minerals in place	-749	-1,017	-89	-6,050
	As of December 31, 2011	15,067	808,681	40,884	1,144,389
	Revisions of previous estimates (4)	-1,489	-210,452	-5,688	-253,513
	Purchases of minerals in place	236	25,532	559	30,301
	Extensions and discoveries (5)	1,011	30,429	1,859	47,649
	Production	-1,110	-42,536	-1,742	-59,647
	Sales of minerals in place	-207	-2,108	-193	-4,510
	As of December 31, 2012	13,508	609,546	35,679	904,669
	Revisions of previous estimates	-760	36,214	4,835	60,663
	Purchases of minerals in place	21	67,291	496	70,395
	Extensions and discoveries (6)	1,342	149,502	10,093	218,112
	Production	-1,027	-42,651	-2,146	-61,690
	Sales of minerals in place	–	-222	-55	-555
	As of December 31, 2013	13,084	819,680	48,902	1,191,594
	Proved developed reserves:
	31-Dec-10	10,923	416,770	15,954	578,032
	31-Dec-11	11,675	557,489	25,359	779,693
	31-Dec-12	11,153	473,223	24,832	689,133
	31-Dec-13	10,443	578,274	29,056	815,268
	Proved undeveloped reserves:
	31-Dec-10	1,965	158,432	11,514	239,308
	31-Dec-11	3,392	251,192	15,525	364,696
	31-Dec-12	2,355	136,323	10,847	215,536
	31-Dec-13	2,641	241,406	19,846	376,326
	_____________
	(1)Thousands of barrels.
	(2)Million cubic feet.
	(3)Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent
	(4)Revisions were primarily attributable to decreased prices used in estimating our reserves (269.9 Bcfe) offset by positive development and production history (16.4 Bcfe).
	(5)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (39.0 Bcfe) and the Appalachian Basin (3.1 Bcfe).
	(6)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (177.1 Bcfe).

Standardized_Measure_Of_Discon

Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves	12 Months Ended
	Dec. 31, 2013
Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves [Abstract]	'
Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves	'
	NOTE 20. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)
	The following tables present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves.  In computing this data, assumptions other than those required by the SEC could produce different results.  Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves.  The following assumptions have been made:
		·		Future cash inflows were based on prices used in estimating our proved oil, natural gas and natural gas liquids reserves.  Future price changes were included only to the extent provided by existing contractual agreements.
		·		Future development and production costs were computed using year end costs assuming no change in present economic conditions.
		·		In accordance with our standing as a non taxable entity, no provisions for future federal income taxes were computed; however, provisions for future obligations under the Texas gross margin tax were computed.
		·		Future net cash flows were discounted at an annual rate of 10%.
	The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is presented below for the years ended December 31:
			2013		2012	2011
	Future cash inflows		$		$	$
			4,998,790		4,005,432	6,334,354
	Future production and development costs		-2,509,542		-1,971,099	-2,873,899
	Future income tax expenses		-22,091		-16,473	-26,131
	Future net cash flows		2,467,157		2,017,860	3,434,324
	10% annual discount for estimated timing of cash flows		-1,427,372		-1,150,928	-2,028,193
	Standardized measure of discounted future net cash flows		$		$	$
			1,039,785		866,932	1,406,131
	As specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were the average prices during the year determined using the price on the first day of each month, except for volumes subject to fixed price contracts.  The prices utilized in calculating our total estimated proved reserves at December 31, 2013, 2012 and 2011 were $96.78 per Bbl of oil, $3.666 per MMBtu of natural gas; $94.71 per Bbl of oil, $2.757 per MMBtu of natural gas; and $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas, respectively.  We do not include our commodity derivatives in the determination of our oil, natural gas and natural gas liquids reserves.
	The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31:
			2013		2012	2011
	Standardized measure at beginning of period		$		$	$
			866,932		1,406,131	1,020,235
	Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs		-194,942		-167,233	-170,705
	Net changes in prices and production costs		-1,264		-292,849	50,201
	Extensions, discoveries and improved recovery, less related costs		113,714		62,367	36,999
	Development costs incurred during the period		17,762		37,501	4,295
	Revisions and other		53,427		-313,955	-20,888
	Accretion of 10% timing discount		87,433		141,723	102,649
	Changes in income taxes		-2,218		3,697	-4,842
	Changes in estimated future development costs		1,692		1,319	10,544
	Changes in timing and other		55,966		-35,046	47,215
	Purchase of minerals in place		41,810		32,906	340,367
	Sales of minerals in place		-527		-9,629	-9,939
	Standardized measure of discounted future net cash flows		$		$	$
			1,039,785		866,932	1,406,131

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Basis Of Presentation	'
	Basis of Presentation
	The consolidated financial statements include the operations of the Partnership and all of its wholly–owned subsidiaries (“we,” “our” or “us”).  All intercompany accounts and transactions have been eliminated in consolidation.  In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.
Use Of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances.  Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.  While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash And Cash Equivalents	'
	Cash and Cash Equivalents
	We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.  All of our cash and cash equivalents are maintained with several major financial institutions in the United States.  Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.
Accounts Receivable	'
	Accounts Receivable
	Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest.  We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.
	As of December 31, 2013 and 2012, we did not have any reserves for doubtful accounts, and we did not incur any expense related to bad debts.  We do not have any off–balance sheet credit exposure related to our customers.
Property And Depreciation	'
	Property and Depreciation
	Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting.  Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.  Lease acquisition costs are capitalized when incurred.  Capitalized costs associated with unproved properties totaled $133.8 million and $133.5 million as of December 31, 2013 and December 31, 2012, respectively.  Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain non–producing leasehold costs are expensed as incurred.  For 2013, 2012 and 2011, we recorded dry hole and exploration costs of $2.4 million, $6.8 million and $12.1 million, respectively.
	No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate.  Sales proceeds are credited to the carrying value of the properties.
	The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers.  Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold and pipeline costs.
	Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to 25 years.  We expense costs for maintenance and repairs in the period incurred.  Significant improvements and betterments are capitalized if they extend the useful life of the asset.
Impairment of Long-Lived Assets	'
	Impairment of Long–Lived Assets
	We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable.  The determination of recoverability is made based upon estimated undiscounted future net cash flows.  The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset.  For 2013, 2012 and 2011, we recorded impairment charges of $76.9 million, $32.4 million and $10.4 million, respectively, related to proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 8).
	Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized.  For 2013, 2012 and 2011, we recorded leasehold impairment charges of $8.5 million, $2.1 million and $0.6 million, respectively, related to unproved oil and natural gas properties.
Investments In Unconsolidated Affiliates	'
	Investments in Unconsolidated Affiliates
	We account for our investments in unconsolidated affiliates using the equity method of accounting.  Accordingly, we recognize our proportionate share of their earnings or losses in the period in which they are reported in their financial statements rather than in the period in which they declare a dividend.  Dividends received from these unconsolidated affiliates decrease the carrying amount of our investments.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells.  After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.  If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.
Revenue Recognition	'
	Revenue Recognition
	Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.  We follow the sales method of accounting for natural gas revenues.  Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest.  An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production.  Under the sales method, no receivables are recorded where we have taken less than our share of production.  There were no significant gas imbalances at December 31, 2013 or 2012.
	We own and operate a network of natural gas gathering systems in the Monroe field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines.  Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.
Income Taxes	'
	Income Taxes
	We are a partnership that is not taxable for federal income tax purposes.  As such, we do not directly pay federal income tax.  As appropriate, our taxable income or loss is includable in the federal income tax returns of our partners.  Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.
	We record our obligations under the Texas gross margin tax as “Income taxes” in our consolidated statement of operations.
Net Income Per Limited Partner Unit	'
	Net Income per Limited Partner Unit
	Our partnership agreement contains incentive distribution rights.  Accordingly, net income used in the determination of net income per limited partner unit for the current reporting period is to be reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that reporting period.  The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement.  Our partnership agreement does not allow for the distribution of undistributed earnings to the holders of the incentive distribution rights, as it limits distributions to the holders of the incentive distribution rights to available cash as defined in the partnership agreement.  Basic and diluted net income per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period.
Derivatives	'
	Derivatives
	We monitor our exposure to various business risks, including commodity price and interest rate risks, and use derivatives to manage the impact of certain of these risks.  Our policies do not permit the use of derivatives for speculative purposes.  We use energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil, natural gas and natural gas liquids.
	We have elected not to designate our derivatives as hedging instruments.  Changes in the fair value of derivatives are recorded immediately to earnings as “(Loss) gain on derivatives, net” in our consolidated statements of operations.
Concentration Of Credit Risk	'
	Concentration of Credit Risk
	All of our derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss.  As of December 31, 2013, all of our counterparties have performed pursuant to their derivative contracts.
	Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.  We have experienced no significant credit losses on such sales in the past.
	In 2013, 2012 and 2011, no customer accounted for greater than 10% of our consolidated oil, natural gas and natural gas liquids revenues.  We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.
Recent Accounting Standards	'
	Recent Accounting Standards
	In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011–11, Disclosures about Offsetting Assets and Liabilities.  This ASU affects all entities that have financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement.  ASU 2011–11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013–01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, to clarify the scope of ASU 2011–11.  The provisions of both ASU 2011–11 and ASU 2013–01 are applicable to annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods.  We adopted ASU 2011–11 and 2013–01 on January 1, 2013, and the adoption did not impact our operating results, financial position or cash flows, but did impact our disclosures on offsetting arrangements (see Note 7).
	No other new accounting pronouncements issued or effective during the year ended December 31, 2013 have had or are expected to have a material impact on our consolidated financial statements.
Subsequent Event	'
	Subsequent Event
	In January 2014, we closed on the sale of our assets held for sale and received proceeds of $5.8 million.
	We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.

EquityBased_Compensation_Table

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Liability Awards [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Activity Related to Units	'
	Activity related to these phantom units is as follows:
	Nonvested phantom units as of December 31, 2012	40,263
	Vested	-40,263
	Nonvested phantom units as of December 31, 2013	–
Equity Awards [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Activity Related to Units	'
	Activity related to these phantom units is as follows:
			Weighted Average Grant Date Fair Value per Phantom Unit
		Number of Phantom Units
	Nonvested phantom units as of December 31, 2012	840,649	$50.24
	Granted	306,300	31.92
	Vested	-199,175	42.89
	Forfeited	-25,018	54.27
	Nonvested phantom units as of December 31, 2013	922,756	$45.63
Assumptions Used to Estimate Weighted Average Fair Value	'
	The following assumptions were used to estimate the weighted average fair value of these phantom units for the years ended December 31:
		2013	2012	2011
	Weighted average fair value of phantom units	$31.92	$58.92	$63.87
	Expected volatility	30.78%	37.87%	36.80%
	Risk–free interest rate	0.68%	0.40%	0.40%
	Dividend yield	0.00%	0.00%	0.00%
	Expected life (years)	4	4	4
Performance Units [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Activity Related to Units	'
	Activity related to these performance units is as follows:
			Weighted Average Grant Date Fair Value per Performance Unit
		Number of Performance Units
	Nonvested performance units as of December 31, 2012	318,500	$52.45
	Vested	-83,500	19.73
	Forfeited	-10,000	64.07
	Nonvested performance units as of December 31, 2013	225,000	$64.07
Assumptions Used to Estimate Weighted Average Fair Value	'
	The following assumptions were used to estimate the weighted average fair value of the performance units:
		2011
	Weighted average fair value of performance units	$64.07
	Expected volatility	47.99%
	Risk–free interest rate	0.56%
	Expected quarterly distribution amount	$0.76
	Expected life (years)	2.69

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisition [Line Items]	'
Pro Forma Revenues, Net Income And Net Income Per Limited Partner Unit	'
	We accounted for these acquisitions as business combinations.  The following table reflects pro forma revenues, net income and net income per limited partner unit for the year ended December 31, 2011 as if these acquisitions had taken place on January 1, 2010.  These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the period presented or that may be obtained in the future.
		2011
	Revenues	$
		350,229
	Net income	140,409
	Net income per limited partner unit:
	Basic	$3.80
	Diluted	$3.77
Business Acquisitions 2013 [Member]	'
Business Acquisition [Line Items]	'
Recognized Fair Values Of Identifiable Assets Acquired And Liabilities Assumed	'
	The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with the November 2013 acquisitions are as follows:
	Accounts receivable – related party	$
		-650
	Other current assets	57
	Proved oil and natural gas properties	60,607
	Unproved oil and natural gas properties	6,018
	Other assets	900
	Accounts payable and accrued liabilities	18
	Asset retirement obligations	-976
		$
		65,974
Business Acquisitions 2011 [Member]	'
Business Acquisition [Line Items]	'
Recognized Fair Values Of Identifiable Assets Acquired And Liabilities Assumed	'
	The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with all of these acquisitions are as follows:
	Accounts receivable	$
		2,698
	Other current assets	1,584
	Proved oil and natural gas properties	428,478
	Unproved oil and natural gas properties	43,947
	Other property	12
	Other assets	7,706
	Accounts payable and accrued liabilities	-523
	Asset retirement obligations	-19,855
		$
		464,047

Investments_In_Unconsolidated_1

Investments In Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2013
Investments In Unconsolidated Affiliates [Abstract]	'
Summary of Financial Information for Unconsolidated Affiliates	'
	Summarized combined financial information for Cardinal and UEO is as follows as of and for the years ended December 31:
		2013	2012
	Current assets	$71,153	$82,609
	Noncurrent assets	1,528,518	389,799
	Total assets	$	$
		1,599,671	472,408
	Current liabilities	$	$
		145,006	75,004
	Owner’s equity	1,454,665	397,404
	Total liabilities and owner’s equity	$	$
		1,599,671	472,408
	Revenues	$	$
		56,888	3,124
	Operating income (loss)	4,955	-1,654
	Net income (loss)	5,125	-1,568

Risk_Management_Tables

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2013
Risk Management [Abstract]	'
Schedule of Commodity Contracts	'
	As of December 31, 2013, we had entered into commodity contracts with the following terms:
			Weighted Average Fixed Price
		Hedged Volume
	Period Covered
	Oil (MBbls):
	Swaps – 2014	1,517.7	$91.19
	Swaps – 2015	730.0	90.09
	Natural Gas (MmmBtus):
	Swaps – 2014	39,712.0	4.7
	Swaps – 2015	36,317.5	4.94
	Swaps – 2016	10,980.0	4.17
Interest Rate Swaps	'
	As of December 31, 2013, we had also entered into interest rate swaps with the following terms:
		Notional Amount	Floating	Fixed
	Period Covered		Rate	Rate
	January 2014 – July 2015	$	1 Month LIBOR	3.315%
		110,000
Fair Value of Derivatives	'
	The following table sets forth the fair values and classification of our outstanding derivatives:
				Net Amounts
				Am
			Gross Amounts	of Assets
		Gross Amounts	Offset in the	Presented in the
		of Recognized	Consolidated	Consolidated
		Assets	Balance Sheets	Balance Sheets
	Derivatives:
	As of December 31, 2013:
	Derivative asset	$	$	$
		24,950	-11,407	13,543
	Long–term derivative asset	30,903	-1,815	29,088
	Total	$	$	$
		55,853	-13,222	42,631
	As of December 31, 2012:
	Derivative asset	$	$	$
		44,173	-3,402	40,771
	Long–term derivative asset	50,692	-4,853	45,839
	Total	$	$	$
		94,865	-8,255	86,610
				Net Amounts
				Am
			Gross Amounts	of Liabilities
		Gross Amounts	Offset in the	Presented in the
		of Recognized	Consolidated	Consolidated
		Liabilities	Balance Sheets	Balance Sheets
	Derivatives:
	As of December 31, 2013:
	Derivative liability	$	$	$
		14,755	-11,407	3,348
	Long–term derivative liability	1,815	-1,815	–
	Total	$	$	$
		16,570	-13,222	3,348
	As of December 31, 2012:
	Derivative liability	$	$	$                   –
		3,402	-3,402
	Long–term derivative liability	4,853	-4,853	–
	Total	$	$	$                   –
		8,255	-8,255

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Recurring Basis	'
	The following table presents the fair value hierarchy table for our net assets and liabilities that are required to be measured at fair value on a recurring basis:
			Fair Value Measurements at the End of the Reporting Period
			Quoted Prices in Active Markets for Identical Assets
			(Level 1)
				Significant Other Observable Inputs
				(Level 2)	Significant Unobservable Inputs
					(Level 3)
		Fair Value
	As of December 31, 2013:
	Assets – Commodity contracts	$	$–	$	$–
		55,853		55,853
	Liabilities:
	Commodity contracts	$	$             –	$	$             –
		11,560		11,560
	Interest rate swaps	5,010	–	5,010	–
	Total	$	$–	$	$–
		16,570		16,570
	As of December 31, 2012:
	Assets – Commodity contracts	$	$–	$	$–
		94,865		94,865
	Liabilities – Interest rate swaps	$	$–	$	$–
		8,255		8,255
Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Nonrecurring Basis	'
	The following table presents the fair value hierarchy table for our net assets and liabilities that are required to be measured at fair value on a nonrecurring basis:
			Fair Value Measurements at the End of the Reporting Period
			Quoted Prices in Active Markets for Identical Assets
			(Level 1)
				Significant Other Observable Inputs
				(Level 2)	Significant Unobservable Inputs
					(Level 3)
						Total
		Fair Value				Losses
	Year ending December 31:
	2013:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		55,163			55,163	76,342
	Long–lived assets held for sale	8,012	–	8,012	–	514
		$	$          –	$	$	$
		63,175		8,012	55,163	76,856
	2012:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		34,214			34,214	31,876
	Long–lived assets held for sale	6,014	–	6,014	–	491
		$	$          –	$	$	$
		40,228		6,014	34,214	32,367
	2011:00:00
	Long–lived assets held for sale	$	$          –	$	$–	$
		15,784		15,784		10,399

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Changes in Aggregate Asset Retirement Obligations	'
	The changes in the aggregate ARO are as follows:
	Balance as of December 31, 2011	$
		93,225
	Liabilities incurred and assumed in acquisitions	5,344
	Accretion expense	5,116
	Revisions in estimated cash flows	7,637
	Settlements and divestitures	-6,638
	Balance as of December 31, 2012	104,684
	Liabilities incurred and assumed in acquisitions	1,852
	Accretion expense	4,925
	Revisions in estimated cash flows	-6,704
	Settlements and divestitures	-1,584
	Balance as of December 31, 2013	$
		103,173

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Redemption Prices on Applicable Redemption Dates	'
	On and after April 15, 2015, we may redeem all or a part of the Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes to be redeemed to the applicable redemption date, if redeemed during the twelve–month period beginning on April 15 of the years indicated below:
	Year	Percentage
	2015	104.00%
	2016	102.00%
	2017 and thereafter	100.00%

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Schedule of Future Minimum Transportation Fees	'
	As of December 31, 2013, our future minimum transportation fees under this agreement are as follows for the years ended December 31:
	13
	2014	$
		618
	2015	619
	2016	618
	2017	619
	2018	618
	Thereafter	2,268
		$
		5,360

Owners_Equity_Tables

Owners' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Target Incentive Distribution To Partners [Line Items]	'
Summary of Distributions Paid	'
	The following sets forth the distributions we paid during the years ended December 31, 2013 and 2012:
			Distribution per Unit	Total Distribution
	Date Paid	Period Covered
	14-Feb-13	October 1, 2012 – December 31, 2012	$	$
			0.767	33,838
	15-May-13	January 1, 2013 – March 31, 2013	0.768	33,883
	14-Aug-13	April 1, 2013 – June 30, 2013	0.769	33,925
	14-Nov-13	July 1, 2013 – September 30, 2013	0.770	38,480
				$
				140,126
	14-Feb-12	October 1, 2011 – December 31, 2011	$	$
			0.763	29,815
	15-May-12	January 1, 2012 – March 31, 2012	0.764	32,994
	August 14 2012	April 1, 2012 – June 30, 2012	0.765	33,036
	14-Nov-12	July 1, 2012 – September 30, 2012	0.766	33,079
				$
				128,924
Subsequent to IDR reset election [Member]	'
Target Incentive Distribution To Partners [Line Items]	'
General Partner Incentive Distributions with respect to Specified Target Levels	'
	Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
			Marginal Percentage Interest in Distributions
		Total Quarterly Distributions Target Amount	Limited Partner	General Partner
	Minimum quarterly distribution	$0.76	98%	2%
	First target distribution	Up to $0.875725	98%	2%
	Second target distribution	Above $0.875725, up to $0.951875	85%	15%
	Thereafter	Above $0.951875	75%	25%

Net_Loss_Income_Per_Limited_Pa1

Net (Loss) Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Net (Loss) Income Per Limited Partner Unit [Abstract]	'
Calculation of Net Income (Loss) Per Limited Partner Unit	'
	The following sets forth the calculation of net (loss) income per limited partner unit for the years ended December 31:
		2013	2012	2011
	Net (loss) income	$	$	$
		-76,227	-16,349	102,641
	Incentive distribution rights	–	–	-8,833
	General partner’s 2% interest in net (loss) income	1,525	327	-2,053
	Net (loss) income attributable to participating securities	-2,006	–	–
	Limited partners’ interest in net (loss) income	$	$	$
		-76,708	-16,022	91,755
	Weighted average limited partner units outstanding:
	Common units	43,691	38,156	33,532
	Class B units	–	3,662	212
	Performance units	–	134	151
	Denominator for basic net (loss) income per limited partner unit	43,691	41,952	33,895
	Dilutive phantom units (1)	–	–	288
	Total	43,691	41,952	34,183
	Net (loss) income per limited partner unit:
	Basic	($1.76)	($0.38)	$2.71
	Diluted	($1.76)	($0.38)	$2.68
	_____________
	(1)Units totaling 0.2 million and 0.8 million units were not included in the computation of diluted net (loss) income per limited partner unit for 2013 and 2012, respectively, because the effect would have been anti-dilutive.

Other_Supplemental_Information1

Other Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2013
Other Supplemental Information [Abstract]	'
Supplemental Cash Flows and Non-Cash Transactions	'
	Supplemental cash flows and non–cash transactions were as follows as of and for the years ended December 31:
		2013	2012	2011
	Supplemental cash flows information:
	Cash paid for interest, net of capitalized interest of $7,276 and $906 at December 31, 2013 and 2012, respectively	$	$	$
		45,355	47,903	21,880
	Cash paid for income taxes	325	340	265
	Non–cash transactions:
	Costs for additions to oil and natural gas properties in         accounts payable and accrued liabilities	19,450	13,951	12,046
	Purchase price adjustment in accounts receivable	–	7,969	–
	Cost for acquisition of oil and natural gas properties in accounts payable and accrued liabilities			423
		–	–
Schedule of Accounts Payable and Accrued Liabilities	'
	Accounts payable and accrued liabilities consisted of the following as of December 31:
		2013	2012
	Costs for additions to oil and natural gas properties	$	$13,951
		19,450
	Lease operating expenses	7,793	7,309
	Interest	8,701	8,566
	Production and ad valorem taxes	4,862	4,379
	General and administrative expenses	2,082	2,596
	Current portion of ARO	1,885	1,977
	Derivative settlements	1,443	364
	Other	660	1,029
	Total	$	$
		46,876	40,171

Quarterly_Data_Tables

Quarterly Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Data [Abstract]	'
Schedule of Quarterly Data	'
		First	Second Quarter	Third	Fourth Quarter
		Quarter		Quarter
	2013
	Revenues	$	$	$	$
		73,702	81,602	81,414	78,594
	Gross profit (1)	43,949	51,510	51,526	49,144
	Net (loss) income	-46,581	32,854	-12,314	-50,186
	Net (loss) income per limited partner unit:
	Basic	($1.08)	$0.74	($0.29)	($1.06)
	Diluted	($1.08)	$0.74	($0.29)	($1.06)
	2012
	Revenues	$	$	$	$
		77,731	63,552	68,701	75,496
	Gross profit (1)	45,204	35,676	40,631	46,853
	Net income (loss)	28,593	14,956	-50,019	-9,879
	Net income (loss) per limited partner unit:
	Basic	$0.69	$0.35	($1.15)	($0.23)
	Diluted	$0.69	$0.34	($1.15)	($0.23)
	_____________
	(1)Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Summarized Financial Information	'
	Summarized financial information for our operating segments is shown below:
		Exploration and Production
				Consolidated
			Midstream	Total
	Year ended December 31, 2013:
	Total revenues	$	$             –	$
		315,312		315,312
	Segment profit	193,749	–	193,749
	Equity in (loss) income of unconsolidated affiliates	259	-603	-344
	Year ended December 31, 2012:
	Total revenues	285,480	–	285,480
	Segment profit	161,593	–	161,593
	Equity in (loss) income of unconsolidated affiliates	156	-138	18
	As of December 31, 2013:
	Capital expenditures	175,870	–	175,870
	Total assets	1,950,300	254,683	2,204,983
	As of December 31, 2012:
	Capital expenditures	249,048	–	249,048
	Total assets	2,031,228	34,186	2,065,414
Reconciliation of Segment Profits	'
	The following table reconciles the segment profits reported above to loss before income taxes and (loss) income from unconsolidated affiliates for the years ended December 31:
		2013	2012
	Segment profit	$	$
		193,749	161,593
	Asset retirement obligations accretion expense	-4,925	-5,116
	Depreciation, depletion and amortization	-113,818	-113,381
	General and administrative expenses	-40,677	-42,682
	Impairment of oil and natural gas properties	-85,341	-34,453
	Gain on sales of oil and natural gas properties	41,309	–
	(Loss) gain on derivatives, net	-17,262	66,734
	Interest expense	-49,062	-48,689
	Other income	277	705
	Loss before income taxes and equity in (loss) income from unconsolidated affiliates	$	$
		-75,750	-15,289

Supplementary_Information_On_O1

Supplementary Information On Oil And Natural Gas Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Supplementary Information On Oil And Natural Gas Activities [Abstract]	'
Capitalized Costs Relating to Oil and Natural Gas Producing Activities	'
	Capitalized costs relating to oil and natural gas producing activities are as follows at December 31:
		2013	2012
	Proved oil and natural gas properties	$	$
		2,265,069	2,131,616
	Unproved oil and natural gas properties	133,763	133,480
		2,398,832	2,265,096
	Accumulated depreciation, depletion and amortization	-569,770	-389,206
	Net capitalized costs	$	$
		1,829,062	1,875,890
Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities	'
	Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:
		2013	2012	2011
	Acquisition of oil and natural gas properties:
	Proved	$	$	$
		59,602	36,834	408,633
	Unproved	6,018	75,229	43,947
	Exploration costs	1,764	5,671	6,112
	Development costs	108,486	131,674	77,961
	Total	$	$	$
		175,870	249,408	536,653

Estimated_Proved_Oil_Natural_G1

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves (Tables)	12 Months Ended
	Dec. 31, 2013
Estimated Proved Oil, Natural Gas And Natural Liquids Reserves [Abstract]	'
Changes in Estimated Proved and Estimated Proved Developed Reserves	'
	The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.
				Natural Gas Liquids
		Oil	Natural Gas	(MBbls) (1)
		(MBbls) (1)	(Mmcf) (2)		MMcfe (3)
	Proved developed and undeveloped reserves:
	As of December 31, 2010	12,888	575,202	27,468	817,340
	Revisions of previous estimates	718	-20,204	-123	-16,631
	Purchases of minerals in place	2,506	277,595	14,405	379,060
	Extensions and discoveries	595	6,352	319	11,839
	Production	-891	-29,247	-1,096	-41,169
	Sales of minerals in place	-749	-1,017	-89	-6,050
	As of December 31, 2011	15,067	808,681	40,884	1,144,389
	Revisions of previous estimates (4)	-1,489	-210,452	-5,688	-253,513
	Purchases of minerals in place	236	25,532	559	30,301
	Extensions and discoveries (5)	1,011	30,429	1,859	47,649
	Production	-1,110	-42,536	-1,742	-59,647
	Sales of minerals in place	-207	-2,108	-193	-4,510
	As of December 31, 2012	13,508	609,546	35,679	904,669
	Revisions of previous estimates	-760	36,214	4,835	60,663
	Purchases of minerals in place	21	67,291	496	70,395
	Extensions and discoveries (6)	1,342	149,502	10,093	218,112
	Production	-1,027	-42,651	-2,146	-61,690
	Sales of minerals in place	–	-222	-55	-555
	As of December 31, 2013	13,084	819,680	48,902	1,191,594
	Proved developed reserves:
	31-Dec-10	10,923	416,770	15,954	578,032
	31-Dec-11	11,675	557,489	25,359	779,693
	31-Dec-12	11,153	473,223	24,832	689,133
	31-Dec-13	10,443	578,274	29,056	815,268
	Proved undeveloped reserves:
	31-Dec-10	1,965	158,432	11,514	239,308
	31-Dec-11	3,392	251,192	15,525	364,696
	31-Dec-12	2,355	136,323	10,847	215,536
	31-Dec-13	2,641	241,406	19,846	376,326
	_____________
	(1)Thousands of barrels.
	(2)Million cubic feet.
	(3)Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent
	(4)Revisions were primarily attributable to decreased prices used in estimating our reserves (269.9 Bcfe) offset by positive development and production history (16.4 Bcfe).
	(5)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (39.0 Bcfe) and the Appalachian Basin (3.1 Bcfe).
	(6)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (177.1 Bcfe).

Standardized_Measure_Of_Discon1

Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves (Tables)	12 Months Ended
	Dec. 31, 2013
Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves [Abstract]	'
Standardized Measure of Discounted Future Net Cash Flows Relating to Estimated Proved Oil, Natural Gas and Natural Gas Liquids Reserves	'
	The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is presented below for the years ended December 31:
		2013	2012	2011
	Future cash inflows	$	$	$
		4,998,790	4,005,432	6,334,354
	Future production and development costs	-2,509,542	-1,971,099	-2,873,899
	Future income tax expenses	-22,091	-16,473	-26,131
	Future net cash flows	2,467,157	2,017,860	3,434,324
	10% annual discount for estimated timing of cash flows	-1,427,372	-1,150,928	-2,028,193
	Standardized measure of discounted future net cash flows	$	$	$
		1,039,785	866,932	1,406,131
Principal Sources of Changes in Standardized Measure of Future Net Cash Flows	'
	The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31:
		2013	2012	2011
	Standardized measure at beginning of period	$	$	$
		866,932	1,406,131	1,020,235
	Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	-194,942	-167,233	-170,705
	Net changes in prices and production costs	-1,264	-292,849	50,201
	Extensions, discoveries and improved recovery, less related costs	113,714	62,367	36,999
	Development costs incurred during the period	17,762	37,501	4,295
	Revisions and other	53,427	-313,955	-20,888
	Accretion of 10% timing discount	87,433	141,723	102,649
	Changes in income taxes	-2,218	3,697	-4,842
	Changes in estimated future development costs	1,692	1,319	10,544
	Changes in timing and other	55,966	-35,046	47,215
	Purchase of minerals in place	41,810	32,906	340,367
	Sales of minerals in place	-527	-9,629	-9,939
	Standardized measure of discounted future net cash flows	$	$	$
		1,039,785	866,932	1,406,131

Organization_And_Nature_Of_Bus1

Organization And Nature Of Business (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
	segment
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]	'
General partner interest in the partnership, percentage	2.00%
Number of reportable segments	2
EnerVest, Ltd. [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]	'
Percentage of ownership interest in EV Energy GP, L.P. ("EV Energy GP")	71.25%
General partner interest in the partnership, percentage	2.00%

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Subsequent Event [Member]

Proved Oil and Natural Gas Properties [Member]

Proved Oil and Natural Gas Properties [Member]

Proved Oil and Natural Gas Properties [Member]

Unproved Oil and Natural Gas Properties [Member]

Unproved Oil and Natural Gas Properties [Member]

Unproved Oil and Natural Gas Properties [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Minimum [Member]

Maximum [Member]

customer

Sales Revenue, Goods, Net [Member]

Significant Accounting Policies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized costs associated with unproved properties

$133,800,000

$133,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Dry hole and exploration costs

2,380,000

6,771,000

12,140,000

'

'

'

'

'

'

'

'

'

'

'

Estimated economic lives of other property

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'25 years

Impairment of oil and natural gas properties

85,341,000

34,453,000

11,037,000

'

76,900,000

32,400,000

10,400,000

8,500,000

2,100,000

600,000

'

'

'

'

Concentration risk, percentage

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

Concentration risk, number of clients

'

'

'

'

'

'

'

'

'

'

0

'

'

'

Proceeds from sale of assets held for sale

'

'

'

$5,800,000

'

'

'

'

'

'

'

'

'

'

EquityBased_Compensation_Narra

Equity-Based Compensation (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Amount of common units that may be awarded under long-term incentive plan	'	4,500,000	'	'
Date equity award compensation plan expires	'	20-Sep-16	'	'
Liability Awards [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Phantom units vesting period	'	'4 years	'	'
Total fair value units vested	'	$2.40	$2.80	$3.50
Compensation cost related to phantom or performance units recognized	'	0.2	2.5	3
Equity Awards [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Phantom units vesting period	'	'4 years	'	'
Total fair value units vested	'	8.5	4.8	2.1
Compensation cost related to phantom or performance units recognized	'	11.9	8.4	4.9
Unrecognized compensation cost related to unvested phantom units	'	30.2	'	'
Unrecognized compensation costs, weighted average period of recognition	'	'2 years 10 months 24 days	'	'
Years used to calculate estimated volatility	'	'2 years	'2 years	'2 years
Performance Units [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance units issued to employees and executive officers	300,000	'	'	'
Percentage of performance units vested over the vesting period	25.00%	'	'	'
Number of performance units estimated using the Black-Scholes option pricing model	100,000	'	'	'
Total fair value units vested	'	1.6	1.7	0.2
Compensation cost related to phantom or performance units recognized	'	5.4	5.6	2
Unrecognized compensation cost related to unvested phantom units	'	$5.60	'	'
Unrecognized compensation costs, weighted average period of recognition	'	'1 year	'	'

EquityBased_Compensation_Activ

Equity-Based Compensation (Activity Related To Units) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Liability Awards [Member]	'	'	'
Number of Units	'	'	'
Nonvested phantom units as of December 31, 2012	40,263	'	'
Vested	-40,263	'	'
Nonvested Phantom units as of December 31, 2013	'	'	'
Equity Awards [Member]	'	'	'
Number of Units	'	'	'
Nonvested phantom units as of December 31, 2012	840,649	'	'
Granted	306,300	'	'
Vested	-199,175	'	'
Forfeited	-25,018	'	'
Nonvested Phantom units as of December 31, 2013	922,756	840,649	'
Weighted Average Grant Date Fair Value per Phantom Unit	'	'	'
Nonvested phantom units as of December 31, 2012	$50.24	'	'
Granted	$31.92	$58.92	$63.87
Vested	$42.89	'	'
Forfeited	$54.27	'	'
Nonvested Phantom units as of December 31, 2013	$45.63	$50.24	'
Performance Units [Member]	'	'	'
Number of Units	'	'	'
Nonvested phantom units as of December 31, 2012	318,500	'	'
Vested	-83,500	'	'
Forfeited	-10,000	'	'
Nonvested Phantom units as of December 31, 2013	225,000	'	'
Weighted Average Grant Date Fair Value per Phantom Unit	'	'	'
Nonvested phantom units as of December 31, 2012	$52.45	'	'
Granted	'	'	$64.07
Vested	$19.73	'	'
Forfeited	$64.07	'	'
Nonvested Phantom units as of December 31, 2013	$64.07	'	'

EquityBased_Compensation_Assum

Equity-Based Compensation (Assumptions Used To Estimate Weighted Average Fair Value) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Awards [Member]	'	'	'
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]	'	'	'
Weighted average fair value of phantom units	$31.92	$58.92	$63.87
Expected volatility	30.78%	37.87%	36.80%
Risk-free interest rate	0.68%	0.40%	0.40%
Dividend yield	0.00%	0.00%	0.00%
Expected life (years)	'4 years	'4 years	'4 years
Performance Units [Member]	'	'	'
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]	'	'	'
Weighted average fair value of phantom units	'	'	$64.07
Expected volatility	'	'	47.99%
Risk-free interest rate	'	'	0.56%
Expected quarterly distribution amount	'	'	$0.76
Expected life (years)	'	'	'2 years 8 months 9 days

Acquisitions_Narrative_Details

Acquisitions (Narrative) (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 30, 2012

Nov. 01, 2011

31-May-12

Dec. 31, 2011

Apr. 30, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Feb. 29, 2012

Dec. 20, 2011

Dec. 01, 2011

Dec. 31, 2010

Dec. 31, 2012

Aug. 31, 2011

Mar. 31, 2013

Aug. 31, 2012

Mid-Continent Area [Member]

Mid-Continent Area [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Mid-Continent Area and Barnett Shale [Member]

Appalachian Basin [Member]

Appalachian Basin [Member]

Utica Shale [Member]

Utica Shale [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil and natural gas properties acquired interest, percentage

'

'

'

'

'

'

'

'

31.00%

'

31.02%

31.63%

31.63%

31.02%

'

'

'

'

'

Oil and natural gas properties acquired, purchase price

'

'

'

$1,100,000

$74,300,000

'

'

'

$66,000,000

'

$17,300,000

$36,500,000

$271,400,000

$75,700,000

'

$31,100,000

$31,100,000

'

$75,200,000

Oil, natural gas and natural gas liquids revenues

310,883,000

281,749,000

256,370,000

'

1,800,000

'

2,200,000

'

1,400,000

1,700,000

'

'

'

'

'

'

'

'

'

Amount received in relation to final purchase price settlement

'

'

'

'

'

'

'

1,700,000

'

'

'

'

'

'

4,100,000

'

'

8,000,000

'

Amount paid in relation to final purchase price settlement

'

'

'

'

'

900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution related to acquisition

'

'

($1,718,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisitions_Pro_Forma_Revenue

Acquisitions (Pro Forma Revenues, Net Income And Net Income Per Limited Partner Unit) (Details) (Mid-Continent Area and Barnett Shale [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011
Mid-Continent Area and Barnett Shale [Member]	'
Business Acquisition [Line Items]	'
Revenues	$350,229
Net income	$140,409
Net income per limited partner unit:	'
Basic	$3.80
Diluted	$3.77

Acquisitions_Recognized_Fair_V

Acquisitions (Recognized Fair Values Of Identifiable Assets Acquired And Liabilities Assumed) (Details) (USD $)	Nov. 30, 2012	Dec. 31, 2011	Dec. 31, 2013
In Thousands, unless otherwise specified		Business Acquisitions 2011 [Member]	Scenario, Forecast [Member]
			Business Acquisitions 2013 [Member]
Business Acquisition [Line Items]	'	'	'
Accounts receivable	'	$2,698	($650)
Other current assets	'	1,584	57
Proved oil and natural gas properties	'	428,478	60,607
Unproved oil and natural gas properties	'	43,947	6,018
Other property	'	12	'
Other assets	'	7,706	900
Accounts payable and accrued liabilities	'	-523	18
Asset retirement obligations	'	-19,855	-976
Business acquisition, assets acquired (liabilities assumed), net	$1,100	$464,047	$65,974

Divestitures_Narrative_Details

Divestitures (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Aug. 31, 2013	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011
				Utica Shale [Member]	Utica Shale [Member]	Utica Shale [Member]	Utica Shale [Member]	Mid Continent and Central and East Texas Areas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'
Proceeds from sale of oil and natural gas properties	$44,056,000	$5,522,000	$14,012,000	'	$44,100,000	$4,200,000	'	$9,800,000
Proceeds from non-core oil and natural gas properties	'	500,000	'	'	'	'	'	'
Percentage of ownership interest sold	'	'	'	25.00%	'	'	'	'
Completion cost carry, amount	'	'	'	'	'	'	$9,400,000	'

Investments_In_Unconsolidated_2

Investments In Unconsolidated Affiliates (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Jan. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2012	Oct. 31, 2012
			Cardinal Gas Services, LLC [Member]	Cardinal Gas Services, LLC [Member]	Utica East Ohio Midstream LLC [Member]	Utica East Ohio Midstream LLC [Member]	Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member]	Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member]	Minimum [Member]	Maximum [Member]
									Utica East Ohio Midstream LLC [Member]	Utica East Ohio Midstream LLC [Member]
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'	'	'	'	'	'
Equity method investment, ownership percentage	'	'	'	9.00%	'	'	'	'	8.00%	21.00%
Equity method investments, payment for additional ownership interest	'	'	'	'	'	$33,300,000	'	'	'	'
Equity method investment amount exceeding equity	8,200,000	900,000	'	'	'	'	'	'	'	'
Net income (loss)	'	'	$13,800,000	'	($8,700,000)	'	$5,125,000	($1,568,000)	'	'

Investments_In_Unconsolidated_3

Investments In Unconsolidated Affiliates (Summary Of Financial Information For Unconsolidated Affiliates) (Details) (Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Current assets	$71,153	$82,609
Noncurrent assets	1,528,518	389,799
Total assets	1,599,671	472,408
Current liabilities	145,006	75,004
Owner's equity	1,454,665	397,404
Total liabilities and owner's equity	1,599,671	472,408
Revenues	56,888	3,124
Operating loss	4,955	-1,654
Net income (loss)	$5,125	($1,568)

Risk_Management_Schedule_Of_Co

Risk Management (Schedule Of Commodity Contracts) (Details)	12 Months Ended
	Dec. 31, 2013
	MBbls
Oil [Member] | Swaps - 2014 [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Oil, Hedged Volume	1,517.70
Weighted Average Fixed Price	91.19
Oil [Member] | Swaps - 2015 [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Oil, Hedged Volume	730
Weighted Average Fixed Price	90.09
Natural Gas [Member] | Swaps - 2014 [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Natural Gas, Hedged Volume	39,712
Weighted Average Fixed Price	4.7
Natural Gas [Member] | Swaps - 2015 [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Natural Gas, Hedged Volume	36,317.50
Weighted Average Fixed Price	4.94
Natural Gas [Member] | Swaps - 2016 [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Natural Gas, Hedged Volume	10,980
Weighted Average Fixed Price	4.17

Risk_Management_Interest_Rate_

Risk Management (Interest Rate Swaps) (Details) (Interest Rate Swaps Covering January 2014 - July 2015 [Member], London Interbank Offered Rate (LIBOR) [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Interest Rate Swaps Covering January 2014 - July 2015 [Member] | London Interbank Offered Rate (LIBOR) [Member]	'
Derivative Instruments Related to Oil and Gas Production [Line Items]	'
Notional Amount	$110,000
Floating Rate	'1 Month LIBOR
Fixed Rate	3.32%

Risk_Management_Fair_Value_Of_

Risk Management (Fair Value Of Derivatives) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Asset:	'	'
Derivative asset, fair value	$55,853	$94,865
Derivative asset, liability	-13,222	-8,255
Derivative asset	13,543	40,771
Long-term derivative asset	29,088	45,839
Net recorded fair value	42,631	86,610
Derivative Liabilities:	'	'
Derivative liability, fair value	16,570	8,255
Derivative liability, asset	-13,222	-8,255
Derivative liability	3,348	'
Net recorded fair value	3,348	'
Derivative Asset [Member]	'	'
Derivative Asset:	'	'
Derivative asset, fair value	24,950	44,173
Derivative asset, liability	-11,407	-3,402
Derivative asset	13,543	40,771
Long-term Derivative Asset [Member]	'	'
Derivative Asset:	'	'
Derivative asset, fair value	30,903	50,692
Derivative asset, liability	-1,815	-4,853
Long-term derivative asset	29,088	45,839
Derivative Liability [Member]	'	'
Derivative Liabilities:	'	'
Derivative liability, fair value	14,755	3,402
Derivative liability, asset	-11,407	-3,402
Derivative liability	3,348	'
Long-term Derivative Liability [Member]	'	'
Derivative Liabilities:	'	'
Derivative liability, fair value	1,815	4,853
Derivative liability, asset	-1,815	-4,853
Long-term derivative liability	'	'

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Impairment of oil and natural gas properties	$85,341,000	$34,453,000	$11,037,000
Asset retirement obligation	103,173,000	104,684,000	93,225,000
8.0% Senior Notes due 2019 [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Senior notes, fair value	504,700,000	531,200,000	'
Senior notes, carrying value	499,300,000	499,200,000	'
Long-Lived Assets Held and Used [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Oil and natural gas properties, carrying amount	131,500,000	66,100,000	'
Impairment of oil and natural gas properties	76,300,000	31,900,000	'
Oil and natural gas properties, fair value	55,200,000	34,200,000	'
Long-Lived Assets Held For Sale [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Oil and natural gas properties, carrying amount	'	'	26,200,000
Impairment of oil and natural gas properties	500,000	500,000	10,400,000
Oil and natural gas properties, fair value	8,000,000	6,000,000	15,800,000
Asset retirement obligation	$2,200,000	'	'

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Recurring Basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative asset, fair value	$55,853	$94,865
Derivative liability, fair value	16,570	8,255
Recurring basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	16,570	8,255
Recurring basis [Member] | Commodity Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative asset, fair value	55,853	94,865
Derivative liability, fair value	11,560	'
Recurring basis [Member] | Interest Rate Swaps [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	5,010	'
Recurring basis [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	'	'
Recurring basis [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Commodity Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative asset, fair value	'	'
Derivative liability, fair value	'	'
Recurring basis [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Interest Rate Swaps [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	'	'
Recurring basis [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	16,570	8,255
Recurring basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative asset, fair value	55,853	94,865
Derivative liability, fair value	11,560	'
Recurring basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Swaps [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	5,010	'
Recurring basis [Member] | Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	'	'
Recurring basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative asset, fair value	'	'
Derivative liability, fair value	'	'
Recurring basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Swaps [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative liability, fair value	'	'

Fair_Value_Measurements_Fair_V1

Fair Value Measurements (Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Nonrecurring Basis) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	$63,175	$40,228	'
Total losses	76,856	32,367	'
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	'	'	'
Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	8,012	6,014	'
Significant Unobservable Inputs (Level 3) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	55,163	34,214	'
Long-Lived Assets Held and Used [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	55,163	34,214	'
Total losses	76,342	31,876	'
Long-Lived Assets Held and Used [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	'	'	'
Long-Lived Assets Held and Used [Member] | Significant Unobservable Inputs (Level 3) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	55,163	34,214	'
Long-Lived Assets Held For Sale [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	8,012	6,014	15,784
Total losses	514	491	10,399
Long-Lived Assets Held For Sale [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	'	'	'
Long-Lived Assets Held For Sale [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Long-lived assets	$8,012	$6,014	$15,784

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Asset retirement obligation, current	$1,885	$1,977	'
Asset retirement obligation	103,173	104,684	93,225
Long-Lived Assets Held For Sale [Member]	'	'	'
Asset retirement obligation	$2,200	'	'

Asset_Retirement_Obligations_C

Asset Retirement Obligations (Changes in Aggregate Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligations [Abstract]	'	'	'
Balance at beginning of period	$104,684	$93,225	'
Liabilities incurred and assumed in acquisitions	1,852	5,344	'
Accretion expense	4,925	5,116	3,914
Revisions in estimated cash flows	-6,704	7,637	'
Settlements and divestitures	-1,584	-6,638	'
Balance at end of period	$103,173	$104,684	$93,225

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 13, 2012

Mar. 22, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Minimum [Member]

Maximum [Member]

Borrowing Base Determination, Period One

Borrowing Base Determination, Period Two

Senior Notes Redeemable Prior to April 15, 2014

Senior Notes Redeemable Prior to April 15, 2014

8.0% Senior Notes due 2019 [Member]

8.0% Senior Notes due 2019 [Member]

8.0% Senior Notes due 2019 [Member]

8.0% Senior Notes due 2019 [Member]

Letter of Credit [Member]

Maximum [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior secured credit facility, maximum borrowing capacity

$1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

$100,000,000

Senior secured credit facility, expiration date

30-Apr-16

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio required under credit facility

'

'

'

1

'

'

'

'

'

'

'

'

'

'

Total debt to earnings ratio required under credit facility

'

'

'

1

3.5

'

'

'

'

'

'

'

'

'

Weighted average effective interest rate

3.09%

3.53%

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit, borrowing base

730,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing base scheduled redetermination date

'

'

'

'

'

'--04-01

'--10-01

'

'

'

'

'

'

'

Credit facility outstanding

481,000,000

360,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes

'

'

'

'

'

'

'

'

'

200,000,000

300,000,000

'

'

'

Senior unsecured note, offering price at par

'

'

'

'

'

'

'

'

'

103.00%

'

'

'

'

Net proceeds from senior unsecured note

'

'

'

'

'

'

'

'

'

201,900,000

291,500,000

'

'

'

Senior unsecured notes, discount amount

'

'

'

'

'

'

'

'

'

4,100,000

8,500,000

'

'

'

Senior unsecured notes, stated interest rate

'

'

'

'

'

'

'

'

'

'

8.00%

'

'

'

Senior unsecured notes, maturity date

'

'

'

'

'

'

'

'

'

'

'2019

'

'

'

Senior unsecured notes, offering price

'

206,000,000

292,500,000

'

'

'

'

'

'

206,000,000

'

'

'

'

Senior unsecured notes, accrued interest

'

'

'

'

'

'

'

'

'

6,600,000

'

'

'

'

Senior unsecured notes, redemption price

'

'

'

'

'

'

'

108.00%

'

'

'

'

'

'

Senior unsecured notes, redeemable percentage of aggregate principal amount of Notes

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

Senior unsecured notes, percentage of aggregate principal amount outstanding immediately after redemption

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior unsecured notes, redemption period

'180 days

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price if change of control occurs

'

'

'

'

'

'

'

'

'

'

'

101.00%

'

'

Senior notes, carrying value

'

'

'

'

'

'

'

'

'

'

'

$499,300,000

$499,200,000

'

LongTerm_Debt_Redemption_Price

Long-Term Debt (Redemption Prices On Applicable Redemption Dates) (Details)	Dec. 31, 2013
2015 [Member]	'
Debt Disclosure [Line Items]	'
Redemption price, percentage	104.00%
2016 [Member]	'
Debt Disclosure [Line Items]	'
Redemption price, percentage	102.00%
2017 and Thereafter [Member]	'
Debt Disclosure [Line Items]	'
Redemption price, percentage	100.00%

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Minimum [Member]	'
Commitment to fund construction activities for Cardinal and UEO for 2013 and 2014	$140
Maximum [Member]	'
Commitment to fund construction activities for Cardinal and UEO for 2013 and 2014	$160

Commitments_And_Contingencies_2

Commitments And Contingencies (Schedule of Future Minimum Transportation Fees Payment) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments And Contingencies [Abstract]	'
2014	$618
2015	619
2016	618
2017	619
2018	618
Thereafter	2,268
Balance as of December 31, 2013	$5,360

Owners_Equity_Narrative_Detail

Owners' Equity (Narrative) (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Oct. 31, 2013

Feb. 29, 2012

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Dividend Declared [Member]

Executive Officers and Directors [Member]

Prior to IDR reset election

Subsequent to IDR reset election [Member]

Common Unitholders [Member]

Common Unitholders [Member]

Class B Unitholders [Member]

Class B Unitholders [Member]

Stockholders Equity Note [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common unitholders, units issued

'

'

'

'

'

'

'

'

'

'

48,349,080

42,320,707

3,900,000

3,900,000

Common unitholders, units outstanding

'

'

'

'

'

'

'

4,101,541

'

'

48,349,080

42,320,707

'

'

Percentage of limited partnership interest

'

'

'

98.00%

'

'

'

'

'

'

'

'

'

'

Percentage of general partnership interest

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

Public offering number of common units

5,750,000

4,025,000

3,450,000

'

'

'

'

'

'

'

'

'

'

'

Public offering, price per common units

$36.86

$67.95

$44.42

'

'

'

'

'

'

'

'

'

'

'

Net proceeds from public offerings, including contributions

$208,500,000

$267,900,000

$149,800,000

$204,527,000

$262,833,000

$147,108,000

'

'

'

'

'

'

'

'

Contribution from general partner

4,200,000

5,400,000

3,000,000

4,508,000

5,714,000

3,191,000

'

'

'

'

'

'

'

'

Period of distribution of available cash to unitholders after the end of each quarter

'

'

'

'45 days

'

'

'

'

'

'

'

'

'

'

General partner affiliate ownership percentage for call

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

Total quarterly distributions target amount

'

'

'

'

'

'

'

'

$0.40

$0.76

'

'

'

'

Distribution to unitholders declared per unit

'

'

'

'

'

'

$0.77

'

'

'

'

'

'

'

Distribution to unitholders, amount

'

'

'

'

'

'

$38,700,000

'

'

'

'

'

'

'

Distribution to unitholders, record date

'

'

'

'

'

'

10-Feb-14

'

'

'

'

'

'

'

Distribution to unitholders, payment date

'

'

'

'

'

'

14-Feb-14

'

'

'

'

'

'

'

Owners_Equity_General_Partner_

Owners' Equity (General Partner Incentive Distributions With respect To Specified Target Levels) (Details) (Subsequent to IDR reset election [Member], USD $)	12 Months Ended
	Dec. 31, 2013
Minimum Quarterly Distribution [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Total quarterly distributions target amount	$0.76
Marginal Percentage Interest in Distributions, Limited Partner	98.00%
Marginal Percentage Interest in Distributions, General Partner	2.00%
First Target Distribution [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Total quarterly distributions target amount	$0.88
Marginal Percentage Interest in Distributions, Limited Partner	98.00%
Marginal Percentage Interest in Distributions, General Partner	2.00%
Second Target Distribution [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Marginal Percentage Interest in Distributions, Limited Partner	85.00%
Marginal Percentage Interest in Distributions, General Partner	15.00%
Second Target Distribution [Member] | Maximum [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Total quarterly distributions target amount	$0.95
Second Target Distribution [Member] | Minimum [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Total quarterly distributions target amount	$0.88
Thereafter [Member]	'
Distribution Made to Limited Partner [Line Items]	'
Total quarterly distributions target amount	$0.95
Marginal Percentage Interest in Distributions, Limited Partner	75.00%
Marginal Percentage Interest in Distributions, General Partner	25.00%

Owners_Equity_Summary_Of_Distr

Owners' Equity (Summary Of Distributions Paid) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Distribution Made to Limited Partner [Line Items]	'	'	'
Total Distribution	$140,126	$128,924	$115,101
Cash Distributions Period Covered October 1, 2012 to December 31, 2012 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	14-Feb-13	'	'
Distribution per Unit	$0.77	'	'
Total Distribution	33,838	'	'
Cash Distributions Period Covered January 1, 2013 to March 31, 2013 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	15-May-13	'	'
Distribution per Unit	$0.77	'	'
Total Distribution	33,883	'	'
Cash Distributions Period Covered April 1, 2013 to June 30, 2013 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	14-Aug-13	'	'
Distribution per Unit	$0.77	'	'
Total Distribution	33,925	'	'
Cash Distributions Period Covered July 1, 2013 to September 30, 2013 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	14-Nov-13	'	'
Distribution per Unit	$0.77	'	'
Total Distribution	38,480	'	'
Cash Distributions Period Covered October 1, 2011 to December 31, 2011 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	'	14-Feb-12	'
Distribution per Unit	'	$0.76	'
Total Distribution	'	29,815	'
Cash Distributions Period Covered January 1, 2012 to March 31, 2012 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	'	15-May-12	'
Distribution per Unit	'	$0.76	'
Total Distribution	'	32,994	'
Cash Distributions Period Covered April 1, 2012 to June 30, 2012 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	'	14-Aug-12	'
Distribution per Unit	'	$0.77	'
Total Distribution	'	33,036	'
Cash Distributions Period Covered July 1, 2012 to September 30, 2012 [Member]	'	'	'
Distribution Made to Limited Partner [Line Items]	'	'	'
Date Paid	'	14-Nov-12	'
Distribution per Unit	'	$0.77	'
Total Distribution	'	$33,079	'

Net_Loss_Income_Per_Limited_Pa2

Net (Loss) Income Per Limited Partner Unit (Calculation Of Net Income (Loss) Per Limited Partner Unit) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except 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

Earnings Per Share Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net (loss) income

($50,186)

($12,314)

$32,854

($46,581)

($9,879)

[1]

($50,019)

[1]

$14,956

[1]

$28,593

[1]

($76,227)

($16,349)

$102,641

General partner interest in the partnership, percentage

'

'

'

'

'

'

'

'

2.00%

'

'

Net (loss) income attributable to participating securities

'

'

'

'

'

'

'

'

-2,006

'

'

Limited partners' interest in net income (loss)

'

'

'

'

'

'

'

'

-76,708

-16,022

91,755

Weighted average limited partner units outstanding:

'

'

'

'

'

'

'

'

'

'

'

Denominator for basic net income (loss) per limited partner unit

'

'

'

'

'

'

'

'

43,691,000

41,952,000

33,895,000

Dilutive phantom units

'

'

'

'

'

'

'

'

'

'

288,000

[2]

Total

'

'

'

'

'

'

'

'

43,691,000

41,952,000

34,183,000

Net (loss) income per limited partner unit:

'

'

'

'

'

'

'

'

'

'

'

Basic

($1.06)

($0.29)

$0.74

($1.08)

($0.23)

($1.15)

$0.35

$0.69

($1.76)

($0.38)

$2.71

Diluted

($1.06)

($0.29)

$0.74

($1.08)

($0.23)

($1.15)

$0.34

$0.69

($1.76)

($0.38)

$2.68

Equity awards not included in the computation of diluted net (loss) income per limited partner

'

'

'

'

'

'

'

'

200,000

800,000

'

Incentive Distribution Rights [Member]

'

'

'

'

'

'

'

'

'

'

'

Earnings Per Share Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net income available for general partners

'

'

'

'

'

'

'

'

'

'

-8,833

General Partner Interests [Member]

'

'

'

'

'

'

'

'

'

'

'

Earnings Per Share Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net income available for general partners

'

'

'

'

'

'

'

'

1,525

327

-2,053

Common Units [Member]

'

'

'

'

'

'

'

'

'

'

'

Weighted average limited partner units outstanding:

'

'

'

'

'

'

'

'

'

'

'

Denominator for basic net income (loss) per limited partner unit

'

'

'

'

'

'

'

'

43,691,000

38,156,000

33,532,000

Class B Unitholders [Member]

'

'

'

'

'

'

'

'

'

'

'

Earnings Per Share Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net (loss) income

'

'

'

'

'

'

'

'

'

($1,160)

$232

Weighted average limited partner units outstanding:

'

'

'

'

'

'

'

'

'

'

'

Denominator for basic net income (loss) per limited partner unit

'

'

'

'

'

'

'

'

'

3,662,000

212,000

Performance Units [Member]

'

'

'

'

'

'

'

'

'

'

'

Weighted average limited partner units outstanding:

'

'

'

'

'

'

'

'

'

'

'

Denominator for basic net income (loss) per limited partner unit

'

'

'

'

'

'

'

'

'

134,000

151,000

[1]

Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.

[2]

Units totaling 0.2 million and 0.8 million units were not included in the computation of diluted net (loss) income per limited partner unit for 2013 and 2012, respectively, because the effect would have been anti-dilutive.

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Feb. 29, 2012

Dec. 20, 2011

Dec. 01, 2011

Overriding Royalty Interests [Member]

Overriding Royalty Interests [Member]

Overriding Royalty Interests [Member]

Appalachian Basin [Member]

Appalachian Basin [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Administrative fees paid to related party

$10,000,000

$13,100,000

$10,900,000

'

'

'

'

'

'

'

'

'

'

'

Direct expenses incurred and reimbursed to related party

17,100,000

17,500,000

15,500,000

'

'

'

'

'

'

'

'

'

'

'

Percentage of overriding royalty interest carved out

'

'

'

'

'

'

7.50%

'

'

'

'

'

'

'

Limited Partner interest from the newly formed limited partnership

'

'

'

'

'

'

48.00%

'

'

'

'

'

'

'

Percentage of gross revenues to be received

'

'

'

'

'

'

5.64%

'

'

'

'

'

'

'

Equity in (loss) income of unconsolidated affiliates

-344,000

18,000

'

'

200,000

100,000

'

'

'

'

'

'

'

'

Dividends from unconsolidated affiliates

285,000

79,000

'

'

200,000

'

'

'

'

'

'

'

'

'

Oil and natural gas properties acquired, purchase price

'

'

'

$1,100,000

'

'

'

$31,100,000

$31,100,000

$66,000,000

$17,300,000

$36,500,000

$271,400,000

$75,700,000

Other_Supplemental_Information2

Other Supplemental Information (Supplemental Cash Flows And Non-Cash Transactions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental cash flows information:	'	'	'
Cash paid for interest	$45,355	$47,903	$21,880
Cash paid for income taxes	325	340	265
Capitalized interest	7,276	906	'
Non-cash transactions:	'	'	'
Costs for additions to oil and natural gas properties	19,450	13,951	12,046
Purchase price adjustment in accounts receivable	'	7,969	'
Cost for acquisition of oil and natural gas properties in accounts payable and accrued liabilities	'	'	$423

Other_Supplemental_Information3

Other Supplemental Information (Schedule Of Accounts Payable And Accrued Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Other Supplemental Information [Abstract]	'	'
Costs for additions to oil and natural gas properties	$19,450	$13,951
Lease operating expenses	7,793	7,309
Interest	8,701	8,566
Production and ad valorem taxes	4,862	4,379
General and administrative expenses	2,082	2,596
Current portion of ARO	1,885	1,977
Derivative settlements	1,443	364
Other	660	1,029
Total	$46,876	$40,171

Quarterly_Data_Schedule_Of_Qua

Quarterly Data (Schedule Of Quarterly Data) (Details) (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 Data [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Revenues	$78,594		$81,414		$81,602		$73,702		$75,496		$68,701		$63,552		$77,731		$315,312	$285,480	$261,840
Gross profit	49,144	[1]	51,526	[1]	51,510	[1]	43,949	[1]	46,853		40,631		35,676		45,204		'	'	'
Net (loss) income	-50,186		-12,314		32,854		-46,581		-9,879	[1]	-50,019	[1]	14,956	[1]	28,593	[1]	-76,227	-16,349	102,641
Limited partners' interest in net income (loss)	'		'		'		'		'		'		'		'		($76,708)	($16,022)	$91,755
Net (loss) income per limited partner unit:	'		'		'		'		'		'		'		'		'	'	'
Basic	($1.06)		($0.29)		$0.74		($1.08)		($0.23)		($1.15)		$0.35		$0.69		($1.76)	($0.38)	$2.71
Diluted	($1.06)		($0.29)		$0.74		($1.08)		($0.23)		($1.15)		$0.34		$0.69		($1.76)	($0.38)	$2.68
[1]	Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.

Segment_Information_Narrative_

Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
	segment
Segment Reporting [Abstract]	'
Number of reportable segments	2

Segment_Information_Summarized

Segment Information (Summarized Financial Information) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, 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
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$78,594	$81,414	$81,602	$73,702	$75,496	$68,701	$63,552	$77,731	$315,312	$285,480	$261,840
Segment profit	'	'	'	'	'	'	'	'	193,749	161,593	'
Equity in (loss) income of unconsolidated affiliates	'	'	'	'	'	'	'	'	-344	18	'
Capital expenditures	'	'	'	'	'	'	'	'	175,870	249,048	'
Assets	2,204,983	'	'	'	2,065,414	'	'	'	2,204,983	2,065,414	'
Exploration and Production [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	315,312	285,480	'
Segment profit	'	'	'	'	'	'	'	'	193,749	161,593	'
Equity in (loss) income of unconsolidated affiliates	'	'	'	'	'	'	'	'	259	156	'
Capital expenditures	'	'	'	'	'	'	'	'	175,870	249,048	'
Assets	1,950,300	'	'	'	2,031,228	'	'	'	1,950,300	2,031,228	'
Midstream [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Equity in (loss) income of unconsolidated affiliates	'	'	'	'	'	'	'	'	-603	-138	'
Assets	$254,683	'	'	'	$34,186	'	'	'	$254,683	$34,186	'

Segment_Information_Reconcilia

Segment Information (Reconciliation of Segment Profits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting [Abstract]	'	'	'
Segment profit	$193,749	$161,593	'
Asset retirement obligations accretion expense	-4,925	-5,116	-3,914
Depreciation, depletion and amortization	-113,818	-113,381	-74,723
General and administrative expenses	-40,677	-42,682	-34,968
Impairment of oil and natural gas properties	-85,341	-34,453	-11,037
Gain on sales of oil and natural gas properties	41,309	'	4,017
(Loss) gain on derivatives, net	-17,262	66,734	93,907
Interest expense	-49,062	-48,689	-30,568
Other income, net	277	705	325
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	($75,750)	($15,289)	$102,995

Supplementary_Information_On_O2

Supplementary Information On Oil And Natural Gas Activities (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Supplementary Information On Oil And Natural Gas Activities [Abstract]	'	'
Proved oil and natural gas properties	$2,265,069	$2,131,616
Unproved oil and natural gas properties	133,763	133,480
Total oil and gas properties	2,398,832	2,265,096
Accumulated depreciation, depletion and amortization	-569,770	-389,206
Net capitalized costs	$1,829,062	$1,875,890

Supplementary_Information_On_O3

Supplementary Information On Oil And Natural Gas Activities (Costs Incurred In Oil And Natural Gas Property Acquisition And Development Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Acquisition of oil and natural gas properties:	'	'	'
Proved	$59,602	$36,834	$408,633
Unproved	6,018	75,229	43,947
Exploration costs	1,764	5,671	6,112
Development costs	108,486	131,674	77,961
Total	$175,870	$249,408	$536,653

Estimated_Proved_Oil_Natural_G2

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves (Changes In Estimated Proved And Estimated Proved Developed Reserves) (Details)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Mcfe

Mcfe

Mcfe

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Oil [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Natural Gas Liquids [Member]

Barnett Shale [Member]

Barnett Shale [Member]

Appalachian Basin [Member]

Mcfe

Mcfe

Mcfe

Mcfe

Mcfe

Mcfe

MBbls

MBbls

MBbls

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

MMcf

MMcf

MMcf

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

MBbls

MBbls

MBbls

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved developed reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Proved undeveloped reserves [Member]

Mcfe

Mcfe

Mcfe

MBbls

MBbls

MBbls

MBbls

MBbls

MBbls

MMcf

MMcf

MMcf

MMcf

MMcf

MMcf

MBbls

MBbls

MBbls

MBbls

MBbls

MBbls

Reserve Quantities [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves, beginning balance

'

'

'

'

'

'

'

'

'

13,508

[1]

15,067

[1]

12,888

[1]

'

'

'

'

'

'

609,546

[2]

808,681

[2]

575,202

[2]

'

'

'

'

'

'

35,679

[1]

40,884

[1]

27,468

[1]

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves, beginning balance

904,669,000

[3]

1,144,389,000

[3]

817,340,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revisions of previous estimates

'

'

'

'

'

'

'

'

'

-760

[1]

-1,489

[1],[4]

718

[1]

'

'

'

'

'

'

36,214

[2]

-210,452

[2],[4]

-20,204

[2]

'

'

'

'

'

'

4,835

[1]

-5,688

[1],[4]

-123

[1]

'

'

'

'

'

'

'

'

'

Revisions of previous estimates

60,663,000

[3]

-253,513,000

[3],[4]

-16,631,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchases of minerals in place

'

'

'

'

'

'

'

'

'

21

[1]

236

[1]

2,506

[1]

'

'

'

'

'

'

67,291

[2]

25,532

[2]

277,595

[2]

'

'

'

'

'

'

496

[1]

559

[1]

14,405

[1]

'

'

'

'

'

'

'

'

'

Purchase of minerals in place

70,395,000

[3]

30,301,000

[3]

379,060,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extensions and discoveries

'

'

'

'

'

'

'

'

'

1,342

[1],[5]

1,011

[1],[6]

595

[1]

'

'

'

'

'

'

149,502

[2],[5]

30,429

[2],[6]

6,352

[2]

'

'

'

'

'

'

10,093

[1],[5]

1,859

[1],[6]

319

[1]

'

'

'

'

'

'

'

'

'

Extensions and discoveries

218,112,000

[3],[5]

47,649,000

[3],[6]

11,839,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Production

'

'

'

'

'

'

'

'

'

-1,027

[1]

-1,110

[1]

-891

[1]

'

'

'

'

'

'

-42,651

[2]

-42,536

[2]

-29,247

[2]

'

'

'

'

'

'

-2,146

[1]

-1,742

[1]

-1,096

[1]

'

'

'

'

'

'

'

'

'

Production

-61,690,000

[3]

-59,647,000

[3]

-41,169,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Sales of minerals in place

'

'

'

'

'

'

'

'

'

'

-207

[1]

-749

[1]

'

'

'

'

'

'

-222

[2]

-2,108

[2]

-1,017

[2]

'

'

'

'

'

'

-55

[1]

-193

[1]

-89

[1]

'

'

'

'

'

'

'

'

'

Sales of minerals in place

-555,000

[3]

-4,510,000

[3]

-6,050,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves, ending balance

'

'

'

'

'

'

'

'

'

13,084

[1]

13,508

[1]

15,067

[1]

'

'

'

'

'

'

819,680

[2]

609,546

[2]

808,681

[2]

'

'

'

'

'

'

48,902

[1]

35,679

[1]

40,884

[1]

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves, ending balance

1,191,594,000

[3]

904,669,000

[3]

1,144,389,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved undeveloped reserves

'

'

'

'

'

'

'

'

'

2,641

[1]

'

'

'

'

'

2,355

[1]

'

'

241,406

[2]

'

'

'

'

'

136,323

[2]

'

'

19,846

[1]

'

'

'

'

'

10,847

[1]

'

'

'

'

'

Oil and natural gas reserves

'

'

269,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil and natural gas reserves offset by positive development and production history

'

'

16,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Volume produced from oil drilling success

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

177,100,000

39,000,000

3,100,000

Proved developed reserves (energy)

815,268,000

[3]

'

'

689,133,000

[3]

779,693,000

[3]

578,032,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved developed reserves (volume)

'

'

'

'

'

'

'

'

'

10,443

[1]

'

'

11,153

[1]

11,675

[1]

10,923

[1]

'

'

'

578,274

[2]

'

'

473,223

[2]

557,489

[2]

416,770

[2]

'

'

'

29,056

[1]

'

'

24,832

[1]

25,359

[1]

15,954

[1]

'

'

'

'

'

'

Proved undeveloped reserve (volume)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,392

[1]

1,965

[1]

'

'

'

'

'

'

'

251,192

[2]

158,432

[2]

'

'

'

'

'

'

'

15,525

[1]

11,514

[1]

'

'

'

Proved undeveloped reserves (energy)

376,326,000

[3]

'

'

'

'

'

215,536,000

[3]

364,696,000

[3]

239,308,000

[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Thousands of barrels.

[2]

Million cubic feet.

[3]

Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent

[4]

Revisions were primarily attributable to decreased prices used in estimating our reserves (269.9 Bcfe) offset by positive development and production history (16.4 Bcfe).

[5]

Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (177.1 Bcfe).

[6]

Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (39.0 Bcfe) and the Appalachian Basin (3.1 Bcfe).

Standardized_Measure_Of_Discon2

Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future net cash flows, annual discount rate	10.00%	'	'
Oil [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Prices utilized in calculating total estimated proved reserves	96.78	94.71	96.19
Natural Gas [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Prices utilized in calculating total estimated proved reserves	3.666	2.757	4.12

Standardized_Measure_Of_Discon3

Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves (Schedule Of Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves [Abstract]	'	'	'
Future cash inflows	$4,998,790	$4,005,432	$6,334,354
Future production and development costs	-2,509,542	-1,971,099	-2,873,899
Future income tax expenses	-22,091	-16,473	-26,131
Future net cash flows	2,467,157	2,017,860	3,434,324
10% annual discount for estimated timing of cash flows	-1,427,372	-1,150,928	-2,028,193
Standardized measure of discounted future net cash flows	$1,039,785	$866,932	$1,406,131
Future net cash flows, annual discount rate	10.00%	'	'

Standardized_Measure_Of_Discon4

Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves (Principal Sources Of Changes in Standardized Measure Of Future Net Cash Flows) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil, Natural Gas And Natural Gas Liquids Reserves [Abstract]	'	'	'
Standardized measure at beginning of period	$866,932	$1,406,131	$1,020,235
Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	-194,942	-167,233	-170,705
Net changes in prices and production costs	-1,264	-292,849	50,201
Extensions, discoveries and improved recovery, less related costs	113,714	62,367	36,999
Development costs incurred during the period	17,762	37,501	4,295
Revisions and other	53,427	-313,955	-20,888
Accretion of 10% timing discount	87,433	141,723	102,649
Changes in income taxes	-2,218	3,697	-4,842
Changes in estimated future development costs	1,692	1,319	10,544
Changes in timing and other	55,966	-35,046	47,215
Purchase of minerals in place	41,810	32,906	340,367
Sales of minerals in place	-527	-9,629	-9,939
Standardized measure of discounted future net cash flows	$1,039,785	$866,932	$1,406,131
Accretion timing discount rate	10.00%	10.00%	10.00%