Harvest Oil & Gas (HRST) 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	evep
Entity Registrant Name	EV Energy Partners, LP
Entity Central Index Key	1361937
Current Fiscal Year End Date	-19
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		48,810,399
Entity Public Float			$1,762,093,517

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$8,255	$11,698
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	32,758	37,661
Related party	1,043	2,873
Other	4,570	1,111
Derivative asset	113,044	13,543
Other current assets	2,000	6,916
Assets held for sale		8,012
Total current assets	161,670	81,814
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2014, $778,679; December 31, 2013, $569,770	1,710,925	1,829,062
Other property, net of accumulated depreciation and amortization; December 31, 2014, $898; December 31, 2013, $754	1,141	1,259
Restricted cash	33,768
Long-term derivative asset	20,647	29,088
Investments in unconsolidated affiliates	315,491	254,978
Other assets	5,561	8,782
Total assets	2,249,203	2,204,983
Current liabilities:
Accounts payable and accrued liabilities	47,878	46,876
Derivative liability		3,348
Liabilities related to assets held for sale		2,155
Total current liabilities	47,878	52,379
Asset retirement obligations	103,832	99,133
Long-term debt	1,030,391	980,297
Other long-term liabilities	989	1,241
Commitments and contingencies
Owners' equity:
General partner interest	-11,713	-11,785
Total owners' equity	1,066,113	1,071,933
Total liabilities and owners' equity	2,249,203	2,204,983
Common Unitholders [Member]
Owners' equity:
Common unitholders - 48,572,019 units and 48,349,080 units issued and outstanding as of December 31, 2014 and 2013, respectively	$1,077,826	$1,083,718

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Oil and natural gas properties, accumulated depreciation, depletion and amortization	$778,679	$569,770
Other property, accumulated depreciation and amortization	$898	$754
Common Unitholders [Member]
Common unitholders, units issued	48,572,019	48,349,080
Common unitholders, units outstanding	48,572,019	48,349,080

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil, natural gas and natural gas liquids revenues	$334,729	$310,883	$281,749
Transportation and marketing-related revenues	4,676	4,429	3,731
Total revenues	339,405	315,312	285,480
Operating costs and expenses:
Lease operating expenses	105,781	104,465	103,605
Cost of purchased natural gas	3,533	3,242	2,600
Dry hole and exploration costs	6,726	2,380	6,771
Production taxes	11,976	11,476	10,911
Asset retirement obligations accretion expense	4,835	4,925	5,116
Depreciation, depletion and amortization	106,073	113,818	113,381
General and administrative expenses	44,955	40,677	42,682
Impairment of oil and natural gas properties	113,968	85,341	34,453
Gain on sales of oil and natural gas properties	-33,319	-41,309
Total operating costs and expenses	364,528	325,015	319,519
Operating (loss) income	-25,123	-9,703	-34,039
Other income (expense), net:
(Loss) gain on derivatives, net	99,720	-17,262	66,734
Interest expense	-52,578	-49,062	-48,689
Gain on sale of investment in unconsolidated affiliate	92,121
Other income, net	294	277	705
Total other (expense) income, net	139,557	-66,047	18,750
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	114,434	-75,750	-15,289
Income taxes	-476	-133	-1,078
(Loss) income before equity in (loss) income of unconsolidated affiliates	113,958	-75,883	-16,367
Equity in (loss) income of unconsolidated affiliates	15,762	-344	18
Net (loss) income	$129,720	($76,227)	($16,349)
Net (loss) income per limited partner unit:
Basic	$2.58	($1.76)	($0.38)
Diluted	$2.58	($1.76)	($0.38)
Weighted average limited partner units outstanding:
Basic	48,563	43,691	41,952
Diluted	48,563	43,691	41,952
Distributions declared per common unit	$2.82	$3.08	$3.06

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net (loss) income	$129,720	($76,227)	($16,349)
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Dry hole costs	4,141	616	1,100
Asset retirement obligations accretion expense	4,835	4,925	5,116
Depreciation, depletion and amortization	106,073	113,818	113,381
Equity-based compensation	19,289	17,470	16,433
Impairment of oil and natural gas properties	113,968	85,341	34,453
Gain on sales of oil and natural gas properties	-33,319	-41,309
Loss (gain) on derivatives, net	-99,720	17,262	-66,734
Cash settlements of matured derivative contracts	5,313	30,066	114,343
Amortization of deferred loan costs	2,333	2,333	2,183
Gain on sale of investment in unconsolidated affiliate	-92,121
Equity in loss (income) of unconsolidated affiliates	-15,762	344	-18
Distributions from unconsolidated affiliates	337	285	79
Other	-700	-296	2,165
Changes in operating assets and liabilities:
Accounts receivable	3,275	-2,671	-1,773
Other current assets	-1,203	-68	51
Accounts payable and accrued liabilities	2,368	1,316	5,185
Other, net	-627	-706	-100
Net cash flows provided by operating activities	148,200	152,499	209,515
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		-57,976	-120,033
Additions to oil and natural gas properties	-102,761	-97,946	-129,783
Prepaid drilling costs	-2,501	-5,041
Investments in unconsolidated affiliates	-114,108	-221,101	-33,811
Proceeds from sale of oil and natural gas properties	45,183	44,056	5,522
Proceeds from sale of investment in unconsolidated affiliate	161,093
Restricted cash	-33,768
Distributions from unconsolidated affiliates	48	38	19
Settlements from acquired derivatives			4,578
Net cash flows used in investing activities	-46,814	-337,970	-273,508
Cash flows from financing activities:
Long-term debt borrowings	209,000	329,000	160,000
Repayments of long-term debt borrowings	-159,000	-208,000	-460,000
Proceeds from debt offering			206,000
Loan costs paid			-4,152
Proceeds from public equity offerings		204,527	262,833
Offering costs		-226	-304
Contributions from general partner	154	4,508	5,714
Distributions paid	-154,978	-140,126	-128,924
Other	-5
Net cash flows (used in) provided by financing activities	-104,829	189,683	41,167
(Decrease) increase in cash and cash equivalents	-3,443	4,212	-22,826
Cash and cash equivalents - beginning of period	11,698	7,486	30,312
Cash and cash equivalents - end of period	$8,255	$11,698	$7,486

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, 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
Contributions from general partner			154	154
Distributions paid	-151,915		-3,063	-154,978
Equity-based compensation	18,903		386	19,289
Other	-5			-5
Net (loss) income	127,125		2,595	129,720
Balance at Dec. 31, 2014	$1,077,826		($11,713)	$1,066,113

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
Consolidated Statements of Changes in Owners' Equity [Abstract]
Conversion of vested phantom units, units	40,264	41,075
Proceeds from public equity offerings, offering costs	$226	$304

Organization_and_Nature_of_Bus

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2014
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 Utica East Ohio Midstream LLC (“UEO”) and, prior to October 2014, Cardinal Gas Services, LLC (“Cardinal”), 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, 2014
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, 2014 and 2013, 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 $117.7 million and $133.8 million as of December 31, 2014 and December 31, 2013, 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 2014, 2013 and 2012, we recorded dry hole and exploration costs of $6.7 million, $2.4 million and $6.8 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 2014, 2013 and 2012, we recorded impairment charges of $103.3 million, $76.9 million and $32.4 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 2014, 2013 and 2012, we recorded leasehold impairment charges of $10.7 million, $8.5 million and $2.1 million, respectively, related to unproved oil and natural gas properties.
	Restricted Cash
	Restricted cash represents proceeds from the sale of certain oil and natural gas properties we deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
	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, 2014 or 2013.
	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 “Gain (loss) 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, 2014, 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 2014, 2013 and 2012, 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 April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued operations criteria. This ASU requires discontinued operations treatment for disposals of a component or group of components that represent a strategic shift that has or will have a major impact on an entity’s operations or financial results. The provisions of ASU 2014–08 are applicable to annual reporting periods beginning after December 15, 2014 and interim periods within those annual periods. Early adoption is permitted for any annual or interim period for which an entity’s financial statements have not yet been previously issued or made available for issuance. We chose to adopt ASU 2014–08 as of September 30, 2014. There was no material impact on our consolidated financial statements.
	In May 2014, the FASB issued ASU No. 2014–09, Revenue from Contracts with Customers. This ASU will supersede virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We have not yet determined the effect that adopting this ASU will have on our consolidated financial statements.
	In August 2014, the FASB issued AU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.
	No other new accounting pronouncements issued or effective during the year ended December 31, 2014 have had or are expected to have a material impact on our consolidated financial statements.
	Subsequent Event
	In February 2015, we amended our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) covenant to March 31, 2016.  In addition, the borrowing base under the facility was decreased to $650.0 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, 2014
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, 2014, 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:
		2014	2013	2012
	Weighted average fair value of phantom units	$22.77	$31.92	$58.92
	Expected volatility	34.52%	30.78%	37.87%
	Risk–free interest rate	0.87%	0.68%	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, 2013	922,756	$45.63
	Granted	358,100	22.77
	Vested	-254,269	46.74
	Forfeited	-38,262	47.24
	Nonvested phantom units as of December 31, 2014	988,325	$37.00
	The total grant date fair value of the phantom units vested in 2014, 2013 and 2012 was $11.9 million, $8.5 million and $4.8 million, respectively.
	We recognized compensation cost related to these phantom units of $13.9 million, $11.9 million and $8.4 million in 2014, 2013 and 2012.  These costs are included in “General and administrative expenses” in our consolidated statements of operations.
	As of December 31, 2014, there was $24.0 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.8 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.
	The total fair value of the phantom units vested in 2013 and 2012 was $2.4 million and $2.8 million, respectively.
	We recognized compensation cost related to these phantom units of $0.2 million and $2.5 million in 2013 and 2012, 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.
	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, 2013	225,000	$64.07
	Vested	-22,500	64.07
	Forfeited	-9,000	64.07
	Nonvested performance units as of December 31, 2014	193,500	$64.07
	The total grant date fair value of the performance units vested in 2014, 2013 and 2012 was $1.4 million, $1.6 million and $1.7 million, respectively.
	We recognized compensation cost related to our performance units of $5.4 million, $5.4 million and $5.6 million in 2014, 2013 and 2012, respectively.  These costs are included in “General and administrative expenses” in our consolidated statements of operations.
	As of December 31, 2014, there was $0.2 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized in the first quarter of 2015.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
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 represented preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for these acquisitions.  The fair values were finalized in 2014 and resulted in no significant adjustment to the original purchase price allocation.
	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 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.
	In August 2012, we also 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.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2014
Divestitures [Abstract]
Divestitures	NOTE 5. DIVESTITURES
	2014
	We, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $33.8 million. We retained all non–Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments.  Operating results related to the Eagle Ford formation were included in our exploration and production segment.
	We closed on the sale of our nine percent interest in Cardinal for $161.1 million, which included certain purchase price adjustments and transaction-related expenses. The transaction is subject to additional customary purchase price adjustments.  We recognized equity in income (loss) of unconsolidated affiliates related to our interest in Cardinal of $5.4 million, $1.2 million and $(0.1) million in 2014, 2013 and 2012, respectively, and these amounts were reported in our midstream segment.
	The assets and liabilities that were held for sale as of December 31, 2013 were sold for $5.8 million. In conjunction with the sale, we incurred an additional impairment charge of $0.2 million (see Note 8).  Operating results related to these properties were included in our exploration and production segment.
	In addition, we closed on the sale of additional Utica Shale acreage in Ohio and six non–core oil and natural gas wells in the Permian Basin for aggregate proceeds of $5.6 million.
	2013
	We closed on sales of Utica Shale acreage in Ohio and received proceeds of $44.1 million for these acres.
	2012
	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.

Investments_in_Unconsolidated_

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2014
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 our 21% interest and, prior to October 2014, our 9% interest in Cardinal (see Note 5).  Both of these investments 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.
	Summarized balance sheet information for our significant investments in unconsolidated affiliates is as follows as of December 31:
		2014 (1)	2013 (2)
	Current assets	$	$
		98,061	71,153
	Noncurrent assets	1,381,773	1,528,518
	Total assets	$	$
		1,479,834	1,599,671
	Current liabilities	$	$
		37,967	145,006
	Owner’s equity	1,441,867	1,454,665
	Total liabilities and owner’s equity	$	$
		1,479,834	1,599,671
	_____________
	(1)Balance sheet information is for UEO on a stand–alone basis.
	(2)Balance sheet information is for UEO and Cardinal on a combined basis.
	Summarized combined statement of operations information for our significant investments in unconsolidated affiliates is as follows for the years ended December 31:
		2014 (1)	2013	2012
	Revenues	$	$	$
		237,344	56,888	3,124
	Operating income (loss)	109,003	4,955	-1,654
	Net income (loss)	109,660	5,125	-1,568
	_____________
	(1)Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).
	As of December 31, 2014, the excess of our investment over our equity in UEO is $12.5 million.  As of December 31, 2013, the excess of our investment over our equity in Cardinal and UEO is $8.2 million.

Risk_Management

Risk Management	12 Months Ended
	Dec. 31, 2014
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 “Gain (loss) on derivatives, net” in our consolidated statements of operations.
	As of December 31, 2014, we had entered into oil and natural gas derivatives with the following terms:
			Weighted Average Fixed Price
		Hedged Volume
	Period Covered
	Oil (MBbls):
	Swaps – 2015	1,277.5	$90.28
	Swaps – 2016	366.0	90.14
	Natural Gas (MmBtus):
	Swaps – 2015	39,602.5	4.86
	Swaps – 2016	18,300.0	4.07
	As of December 31, 2014, we had also entered into interest rate swaps with the following terms:
		Notional Amount	Floating	Fixed
	Period Covered		Rate	Rate
	January 2015 – 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, 2014:
	Derivative asset	$	$	$
		114,754	-1,710	113,044
	Long–term derivative asset	20,647	–	20,647
	Total	$	$	$
		135,401	-1,710	133,691
	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
				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, 2014:
	Derivative liability	$	$	$                   –
		1,710	-1,710
	Long–term derivative liability	–	–	–
	Total	$	$	$                   –
		1,710	-1,710
	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
	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, 2014 and 2013, 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, 2014
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, 2014:
	Assets – Oil and natural gas derivatives	$	$–	$	$–
		135,401		135,401
	Liabilities – Interest rate swaps	$	$–	$	$–
		1,710		1,710
	As of December 31, 2013:
	Assets – Oil and natural gas derivatives	$	$–	$	$–
		55,853		55,853
	Liabilities:
	Oil and natural gas derivatives	$	$             –	$	$             –
		11,560		11,560
	Interest rate swaps	5,010	–	5,010	–
	Total	$	$–	$	$–
		16,570		16,570
	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 2014.
	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:
	2014:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		83,043			83,043	103,118
	Long–lived assets held for sale	5,801	–	5,801	–	164
		$	$          –	$	$	$
		88,844		5,801	83,043	103,282
	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
	Long–lived Assets Held and Used
	In 2014, as a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices, oil and natural gas properties with an aggregate carrying amount of $186.1 million were written down to their fair value of $83.0 million, resulting in an aggregate impairment charge of $103.1 million.  This impairment charge was included in earnings for 2014.  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 2014, we incurred an additional impairment charge of $0.2 million to write down assets held for sale at December 31, 2013 with a carrying amount of $6.0 million to their fair value of $5.8 million.  This impairment charge was included in earnings for 2014.  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.
	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, 2014 and December 31, 2013, the estimated fair value of our senior notes due 2019 was $427.5 million and $504.7 million, respectively, which differs from the carrying value of $499.4 million and $499.3 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, 2014
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, 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
	Liabilities incurred	753
	Accretion expense	4,835
	Revisions in estimated cash flows	432
	Settlements and divestitures	-3,420
	Balance as of December 31, 2014	$
		105,773
	As of both December 31, 2014 and 2013, $1.9 million 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 was included in “Liabilities related to assets held for sale” in our consolidated balance sheets.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Long-Term Debt [Abstract]
Long-Term Debt	NOTE 10. LONG–TERM DEBT
	Credit Facility
	As of December 31, 2014, 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 EBITDAX of no greater than 3.5 to 1.0.  As of December 31, 2014, 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 2.98% and 3.09% at December 31, 2014 and 2013, 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, 2014, 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 $531.0 million and $481.0 million outstanding under the facility at December 31, 2014 and 2013, respectively.
	8.0% Senior Notes due 2019
	We have $500.0 million outstanding of our 8.0% senior unsecured notes due 2019 (the “Notes”).  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.  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.
	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 $499.4 million and $499.3 million at December 31, 2014 and December 31, 2013, respectively.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013.
	As of December 31, 2014, we expect our aggregate commitment to fund the construction activities for UEO to be between $26.0 million and $32.0 million for 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, 2014, our future minimum transportation fees under this agreement are as follows for the years ended December 31:
	13
	2015	$
		618
	2016	619
	2017	618
	2018	619
	2019	618
	Thereafter	1,650
		$
		4,742

Owners_Equity

Owners' Equity	12 Months Ended
	Dec. 31, 2014
Owners' Equity [Abstract]
Owners' Equity	NOTE 12. OWNERS’ EQUITY
	Units Outstanding
	At December 31, 2014, owner’s equity consists of 48,572,019 common units outstanding (including 4,249,470 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.
	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.
	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.
	The minimum quarterly distribution is not guaranteed and distributions below the minimum quarterly distribution will not be accrued in arrears.
	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, 2014 and 2013:
					Distribution per Unit	Total Distribution
	Date Paid		Period Covered
	14-Feb-14		October 1, 2013 – December 31, 2013		$	$
					0.771	38,696
	15-May-14		January 1, 2014 – March 31, 2014		0.772	38,716
	14-Aug-14		April 1, 2014 – June 30, 2014		0.773	38,760
	14-Nov-14		July 1, 2014 – September 30, 2014		0.774	38,806
						$
						154,978
	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
	On February 2, 2015, the board of directors of EV Management declared a $0.50 per unit distribution for the fourth quarter of 2014 on all common units.  The distribution was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015.  The aggregate amount of the distribution was $25.2 million.

Net_Income_Loss_Per_Limited_Pa

Net Income (Loss) Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2014
Net Income (Loss) Per Limited Partner Unit [Abstract]
Net Income (Loss) Per Limited Partner Unit
	NOTE 13. NET INCOME (LOSS) PER LIMITED PARTNER UNIT
	The following sets forth the calculation of net income (loss) per limited partner unit for the years ended December 31:
		2014	2013	2012
	Net income (loss)	$	$	$
		129,720	-76,227	-16,349
	General partner’s 2% interest in net income (loss)	-2,595	1,525	327
	Net income (loss) attributable to unvested phantom units	-1,723	-2,006	–
	Limited partners’ interest in net income (loss)	$	$	$
		125,402	-76,708	-16,022
	Weighted average limited partner units outstanding:
	Common units	48,563	43,691	38,156
	Class B units	–	–	3,662
	Performance units	–	–	134
	Denominator for basic net income (loss) per limited partner unit		43,691	41,952
	Dilutive phantom units (1)	–	–	–
	Total	48,563	43,691	41,952
	Net income (loss) per limited partner unit:
	Basic	$2.58	($1.76)	($0.38)
	Diluted	$2.58	($1.76)	($0.38)
	_____________
	(1)Unearned performance units totaling 0.2 million, 0.2 million and 0.8 million units were not included in the computation of diluted net income (loss) per limited partner unit for 2014, 2013 and 2012, respectively, because the effect would have been anti-dilutive.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 14. RELATED PARTY TRANSACTIONS
	Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $12.1 million, $10.0 million and $13.1 million in 2014, 2013 and 2012, 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 2014, 2013 and 2012, we reimbursed EnerVest approximately $17.0 million, $17.1 million and $17.5 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 $0.4 million, $0.2 million and $0.1 million of income from unconsolidated affiliates in 2014, 2013 and 2012, respectively, and we received $0.3 million and $0.2 million of distributions in 2014 and 2013, respectively.

Other_Supplemental_Information

Other Supplemental Information	12 Months Ended
	Dec. 31, 2014
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:
		2014	2013	2012
	Supplemental cash flows information:
	Cash paid for interest, net of capitalized interest of $5,741,  $7,276 and $906 at December 31, 2014, 2013 and 2012, respectively	$	$	$
		49,444	45,355	47,903
	Cash paid for income taxes	155	325	340
	Non–cash transactions:
	Costs for additions to oil and natural gas properties in         accounts payable and accrued liabilities	18,028	19,450	13,951
	Purchase price adjustment in accounts receivable	–	–	7,969
	Accounts payable and accrued liabilities consisted of the following as of December 31:
		2014	2013
	Costs for additions to oil and natural gas properties	$	$
		18,028	19,450
	Lease operating expenses	9,701	7,793
	Interest	8,649	8,701
	Production and ad valorem taxes	5,683	4,862
	General and administrative expenses	2,317	2,082
	Current portion of ARO	1,941	1,885
	Derivative settlements	280	1,443
	Other	1,279	660
	Total	$	$
		47,878	46,876

Quarterly_Data

Quarterly Data	12 Months Ended
	Dec. 31, 2014
Quarterly Data [Abstract]
Quarterly Data	NOTE 16. QUARTERLY DATA (UNAUDITED)
		First	Second Quarter	Third	Fourth Quarter
		Quarter		Quarter
	2014
	Revenues	$	$	$	$
		95,339	89,360	84,531	70,175
	Gross profit (1)	65,451	59,433	54,105	39,126
	Net (loss) income	-6,253	-9,023	42,620	102,376
	Net (loss) income per limited partner unit:
	Basic	($0.14)	($0.19)	$0.85	$2.03
	Diluted	($0.14)	($0.19)	$0.85	$2.03
	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)
	_____________
	(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, 2014
Segment Information [Abstract]
Segment Information	NOTE 17. SEGMENT INFORMATION
	We 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 UEO and, through October 2014, Cardinal, 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, gain of sales of oil and natural gas properties, gain (loss) on derivatives, interest expense, gain on sale of investment in unconsolidated affiliate and other income or expense.
	Summarized financial information for our operating segments is shown below:
		Exploration and Production
				Consolidated
			Midstream	Total
	Year ended December 31, 2014:
	Total revenues	$    339,405	$             –	$
				339,405
	Segment profit	211,389	–	211,389
	Equity in income of unconsolidated affiliates	408	15,354	15,762
	Year ended December 31, 2013:
	Total revenues	$	$             –	$
		315,312		315,312
	Segment profit	193,749	–	193,749
	Equity in income (loss) 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 income (loss) of unconsolidated affiliates	156	-138	18
	As of December 31, 2014:
	Capital expenditures	112,409	–	112,409
	Total assets	1,934,030	315,173	2,249,203
	As of December 31, 2013:
	Capital expenditures	175,870	–	175,870
	Total assets	1,950,300	254,683	2,204,983
	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:
		2014	2013	2012
	Segment profit	$	$	$
		211,389	193,749	161,593
	Asset retirement obligations accretion expense	-4,835	-4,925	-5,116
	Depreciation, depletion and amortization	-106,073	-113,818	-113,381
	General and administrative expenses	-44,955	-40,677	-42,682
	Impairment of oil and natural gas properties	-113,968	-85,341	-34,453
	Gain on sales of oil and natural gas properties	33,319	41,309	–
	Gain (loss) on derivatives, net	99,720	-17,262	66,734
	Interest expense	-52,578	-49,062	-48,689
	Gain on sale of investment in unconsolidated affiliate	92,121	–	–
	Other income	294	277	705
	Income (loss) before income taxes and equity in income (loss) from unconsolidated affiliates	$	$	$
		114,434	-75,750	-15,289

Supplementary_Information_on_O

Supplementary Information on Oil and Natural Gas Activities	12 Months Ended
	Dec. 31, 2014
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:
		2014	2013
	Proved oil and natural gas properties	$	$
		2,371,866	2,265,069
	Unproved oil and natural gas properties	117,738	133,763
		2,489,604	2,398,832
	Accumulated depreciation, depletion and amortization	-778,679	-569,770
	Net capitalized costs	$	$
		1,710,925	1,829,062
	Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:
		2014	2013	2012
	Acquisition of oil and natural gas properties:
	Proved	$–	$	$
			59,602	36,834
	Unproved	–	6,018	75,229
	Exploration costs	2,585	1,764	5,671
	Development costs	103,840	108,486	131,674
	Total	$	$	$
		106,425	175,870	249,408

Estimated_Proved_Oil_Natural_G

Estimated Proved Oil, Natural Gas and Natural Liquids Reserves	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 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, 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
	Revisions of previous estimates (7)	-1,851	-138,666	-16,180	-246,856
	Purchases of minerals in place	21	1,515	222	2,974
	Extensions and discoveries (8)	1,900	81,571	5,767	127,571
	Production	-1,052	-43,363	-2,311	-63,540
	Sales of minerals in place	-194	-8,545	-257	-11,247
	As of December 31, 2014	11,908	712,192	36,143	1,000,496
	Proved developed reserves:
	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
	31-Dec-14	9,783	599,664	30,766	842,956
	Proved undeveloped reserves:
	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
	31-Dec-14	2,125	112,528	5,377	157,540
	_____________
	(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).
	(7)Revisions were primarily attributable to the removal of 213.3 Bcfe of reserves that we had planned to develop at December 31, 2013, but based on current prices, we no longer expect to develop within the next five years.
	(8)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 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, 2014
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:
			2014		2013	2012
	Future cash inflows		$		$	$
			4,639,547		4,998,790	4,005,432
	Future production and development costs		-2,123,559		-2,509,542	-1,971,099
	Future income tax expenses		-18,266		-22,091	-16,473
	Future net cash flows		2,497,722		2,467,157	2,017,860
	10% annual discount for estimated timing of cash flows		-1,404,419		-1,427,372	-1,150,928
	Standardized measure of discounted future net cash flows		$		$	$
			1,093,303		1,039,785	866,932
	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, 2014, 2013 and 2012 were $94.99 per Bbl of oil, $4.35 per MMBtu of natural gas; $96.78 per Bbl of oil, $3.666 per MMBtu of natural gas; and $94.71 per Bbl of oil and $2.757 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:
			2014		2013	2012
	Standardized measure at beginning of period		$		$	$
			1,039,785		866,932	1,406,131
	Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs		-216,972		-194,942	-167,233
	Net changes in prices and production costs		131,899		-1,264	-292,849
	Extensions, discoveries and improved recovery, less related costs		113,127		113,714	62,367
	Development costs incurred during the period		23,737		17,762	37,501
	Revisions and other		-69,407		53,427	-313,955
	Accretion of 10% timing discount		104,941		87,433	141,723
	Changes in income taxes		1,725		-2,218	3,697
	Changes in estimated future development costs		-2,980		1,692	1,319
	Changes in timing and other		-28,853		55,966	-35,046
	Purchase of minerals in place		4,376		41,810	32,906
	Sales of minerals in place		-8,075		-527	-9,629
	Standardized measure of discounted future net cash flows		$		$	$
			1,093,303		1,039,785	866,932

Recovered_Sheet1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013, 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 $117.7 million and $133.8 million as of December 31, 2014 and December 31, 2013, 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 2014, 2013 and 2012, we recorded dry hole and exploration costs of $6.7 million, $2.4 million and $6.8 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 2014, 2013 and 2012, we recorded impairment charges of $103.3 million, $76.9 million and $32.4 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 2014, 2013 and 2012, we recorded leasehold impairment charges of $10.7 million, $8.5 million and $2.1 million, respectively, related to unproved oil and natural gas properties.
Restricted Cash	Restricted Cash
	Restricted cash represents proceeds from the sale of certain oil and natural gas properties we deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
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, 2014 or 2013.
	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 “Gain (loss) 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, 2014, 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 2014, 2013 and 2012, 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 April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued operations criteria. This ASU requires discontinued operations treatment for disposals of a component or group of components that represent a strategic shift that has or will have a major impact on an entity’s operations or financial results. The provisions of ASU 2014–08 are applicable to annual reporting periods beginning after December 15, 2014 and interim periods within those annual periods. Early adoption is permitted for any annual or interim period for which an entity’s financial statements have not yet been previously issued or made available for issuance. We chose to adopt ASU 2014–08 as of September 30, 2014. There was no material impact on our consolidated financial statements.
	In May 2014, the FASB issued ASU No. 2014–09, Revenue from Contracts with Customers. This ASU will supersede virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We have not yet determined the effect that adopting this ASU will have on our consolidated financial statements.
	In August 2014, the FASB issued AU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.
	No other new accounting pronouncements issued or effective during the year ended December 31, 2014 have had or are expected to have a material impact on our consolidated financial statements.
Subsequent Event	Subsequent Event
	In February 2015, we amended our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) covenant to March 31, 2016.  In addition, the borrowing base under the facility was decreased to $650.0 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, 2014
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, 2013	922,756	$45.63
	Granted	358,100	22.77
	Vested	-254,269	46.74
	Forfeited	-38,262	47.24
	Nonvested phantom units as of December 31, 2014	988,325	$37.00
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:
		2014	2013	2012
	Weighted average fair value of phantom units	$22.77	$31.92	$58.92
	Expected volatility	34.52%	30.78%	37.87%
	Risk–free interest rate	0.87%	0.68%	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, 2013	225,000	$64.07
	Vested	-22,500	64.07
	Forfeited	-9,000	64.07
	Nonvested performance units as of December 31, 2014	193,500	$64.07

Acquisitions_Tables

Acquisitions (Tables) (Business Acquisitions 2013 [Member])	12 Months Ended
	Dec. 31, 2014
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

Recovered_Sheet2

Investments In Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2014
Investments In Unconsolidated Affiliates [Abstract]
Summary of Financial Information for Unconsolidated Affiliates	Summarized balance sheet information for our significant investments in unconsolidated affiliates is as follows as of December 31:
		2014 (1)	2013 (2)
	Current assets	$	$
		98,061	71,153
	Noncurrent assets	1,381,773	1,528,518
	Total assets	$	$
		1,479,834	1,599,671
	Current liabilities	$	$
		37,967	145,006
	Owner’s equity	1,441,867	1,454,665
	Total liabilities and owner’s equity	$	$
		1,479,834	1,599,671
	_____________
	(1)Balance sheet information is for UEO on a stand–alone basis.
	(2)Balance sheet information is for UEO and Cardinal on a combined basis.
	Summarized combined statement of operations information for our significant investments in unconsolidated affiliates is as follows for the years ended December 31:
		2014 (1)	2013	2012
	Revenues	$	$	$
		237,344	56,888	3,124
	Operating income (loss)	109,003	4,955	-1,654
	Net income (loss)	109,660	5,125	-1,568
	_____________
	(1)Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).

Risk_Management_Tables

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2014
Risk Management [Abstract]
Schedule of Commodity Contracts
	As of December 31, 2014, we had entered into oil and natural gas derivatives with the following terms:
			Weighted Average Fixed Price
		Hedged Volume
	Period Covered
	Oil (MBbls):
	Swaps – 2015	1,277.5	$90.28
	Swaps – 2016	366.0	90.14
	Natural Gas (MmBtus):
	Swaps – 2015	39,602.5	4.86
	Swaps – 2016	18,300.0	4.07
Interest Rate Swaps	As of December 31, 2014, we had also entered into interest rate swaps with the following terms:
		Notional Amount	Floating	Fixed
	Period Covered		Rate	Rate
	January 2015 – 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, 2014:
	Derivative asset	$	$	$
		114,754	-1,710	113,044
	Long–term derivative asset	20,647	–	20,647
	Total	$	$	$
		135,401	-1,710	133,691
	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
				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, 2014:
	Derivative liability	$	$	$                   –
		1,710	-1,710
	Long–term derivative liability	–	–	–
	Total	$	$	$                   –
		1,710	-1,710
	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

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
	Assets – Oil and natural gas derivatives	$	$–	$	$–
		135,401		135,401
	Liabilities – Interest rate swaps	$	$–	$	$–
		1,710		1,710
	As of December 31, 2013:
	Assets – Oil and natural gas derivatives	$	$–	$	$–
		55,853		55,853
	Liabilities:
	Oil and natural gas derivatives	$	$             –	$	$             –
		11,560		11,560
	Interest rate swaps	5,010	–	5,010	–
	Total	$	$–	$	$–
		16,570		16,570
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:
	2014:00:00
	Long–lived assets held and used	$	$          –	$            –	$	$
		83,043			83,043	103,118
	Long–lived assets held for sale	5,801	–	5,801	–	164
		$	$          –	$	$	$
		88,844		5,801	83,043	103,282
	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

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Changes in Aggregate Asset Retirement Obligations	The changes in the aggregate ARO are as follows:
	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
	Liabilities incurred	753
	Accretion expense	4,835
	Revisions in estimated cash flows	432
	Settlements and divestitures	-3,420
	Balance as of December 31, 2014	$
		105,773

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014
Commitments and Contingencies [Abstract]
Schedule of Future Minimum Transportation Fees	As of December 31, 2014, our future minimum transportation fees under this agreement are as follows for the years ended December 31:
	13
	2015	$
		618
	2016	619
	2017	618
	2018	619
	2019	618
	Thereafter	1,650
		$
		4,742

Owners_Equity_Tables

Owners' Equity (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
			Distribution per Unit	Total Distribution
	Date Paid	Period Covered
	14-Feb-14	October 1, 2013 – December 31, 2013	$	$
			0.771	38,696
	15-May-14	January 1, 2014 – March 31, 2014	0.772	38,716
	14-Aug-14	April 1, 2014 – June 30, 2014	0.773	38,760
	14-Nov-14	July 1, 2014 – September 30, 2014	0.774	38,806
				$
				154,978
	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
Subsequent to IDR reset election [Member]
Target Incentive Distribution To Partners [Line Items]
General Partner Incentive Distributions with Respect to Specified Target Levels
	The minimum quarterly distribution is not guaranteed and distributions below the minimum quarterly distribution will not be accrued in arrears.
	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_Income_Loss_Per_Limited_Pa1

Net Income (Loss) Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Net Income (Loss) Per Limited Partner Unit [Abstract]
Calculation of Net Income (Loss) Per Limited Partner Unit	The following sets forth the calculation of net income (loss) per limited partner unit for the years ended December 31:
		2014	2013	2012
	Net income (loss)	$	$	$
		129,720	-76,227	-16,349
	General partner’s 2% interest in net income (loss)	-2,595	1,525	327
	Net income (loss) attributable to unvested phantom units	-1,723	-2,006	–
	Limited partners’ interest in net income (loss)	$	$	$
		125,402	-76,708	-16,022
	Weighted average limited partner units outstanding:
	Common units	48,563	43,691	38,156
	Class B units	–	–	3,662
	Performance units	–	–	134
	Denominator for basic net income (loss) per limited partner unit		43,691	41,952
	Dilutive phantom units (1)	–	–	–
	Total	48,563	43,691	41,952
	Net income (loss) per limited partner unit:
	Basic	$2.58	($1.76)	($0.38)
	Diluted	$2.58	($1.76)	($0.38)
	_____________
	(1)Unearned performance units totaling 0.2 million, 0.2 million and 0.8 million units were not included in the computation of diluted net income (loss) per limited partner unit for 2014, 2013 and 2012, respectively, because the effect would have been anti-dilutive.

Other_Supplemental_Information1

Other Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014	2013	2012
	Supplemental cash flows information:
	Cash paid for interest, net of capitalized interest of $5,741,  $7,276 and $906 at December 31, 2014, 2013 and 2012, respectively	$	$	$
		49,444	45,355	47,903
	Cash paid for income taxes	155	325	340
	Non–cash transactions:
	Costs for additions to oil and natural gas properties in         accounts payable and accrued liabilities	18,028	19,450	13,951
	Purchase price adjustment in accounts receivable	–	–	7,969
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued liabilities consisted of the following as of December 31:
		2014	2013
	Costs for additions to oil and natural gas properties	$	$
		18,028	19,450
	Lease operating expenses	9,701	7,793
	Interest	8,649	8,701
	Production and ad valorem taxes	5,683	4,862
	General and administrative expenses	2,317	2,082
	Current portion of ARO	1,941	1,885
	Derivative settlements	280	1,443
	Other	1,279	660
	Total	$	$
		47,878	46,876

Quarterly_Data_Tables

Quarterly Data (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Data [Abstract]
Schedule of Quarterly Data		First	Second Quarter	Third	Fourth Quarter
		Quarter		Quarter
	2014
	Revenues	$	$	$	$
		95,339	89,360	84,531	70,175
	Gross profit (1)	65,451	59,433	54,105	39,126
	Net (loss) income	-6,253	-9,023	42,620	102,376
	Net (loss) income per limited partner unit:
	Basic	($0.14)	($0.19)	$0.85	$2.03
	Diluted	($0.14)	($0.19)	$0.85	$2.03
	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)
	_____________
	(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, 2014
Segment Information [Abstract]
Summarized Financial Information	Summarized financial information for our operating segments is shown below:
		Exploration and Production
				Consolidated
			Midstream	Total
	Year ended December 31, 2014:
	Total revenues	$    339,405	$             –	$
				339,405
	Segment profit	211,389	–	211,389
	Equity in income of unconsolidated affiliates	408	15,354	15,762
	Year ended December 31, 2013:
	Total revenues	$	$             –	$
		315,312		315,312
	Segment profit	193,749	–	193,749
	Equity in income (loss) 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 income (loss) of unconsolidated affiliates	156	-138	18
	As of December 31, 2014:
	Capital expenditures	112,409	–	112,409
	Total assets	1,934,030	315,173	2,249,203
	As of December 31, 2013:
	Capital expenditures	175,870	–	175,870
	Total assets	1,950,300	254,683	2,204,983
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:
		2014	2013	2012
	Segment profit	$	$	$
		211,389	193,749	161,593
	Asset retirement obligations accretion expense	-4,835	-4,925	-5,116
	Depreciation, depletion and amortization	-106,073	-113,818	-113,381
	General and administrative expenses	-44,955	-40,677	-42,682
	Impairment of oil and natural gas properties	-113,968	-85,341	-34,453
	Gain on sales of oil and natural gas properties	33,319	41,309	–
	Gain (loss) on derivatives, net	99,720	-17,262	66,734
	Interest expense	-52,578	-49,062	-48,689
	Gain on sale of investment in unconsolidated affiliate	92,121	–	–
	Other income	294	277	705
	Income (loss) before income taxes and equity in income (loss) from unconsolidated affiliates	$	$	$
		114,434	-75,750	-15,289

Recovered_Sheet3

Supplementary Information On Oil And Natural Gas Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014	2013
	Proved oil and natural gas properties	$	$
		2,371,866	2,265,069
	Unproved oil and natural gas properties	117,738	133,763
		2,489,604	2,398,832
	Accumulated depreciation, depletion and amortization	-778,679	-569,770
	Net capitalized costs	$	$
		1,710,925	1,829,062
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:
		2014	2013	2012
	Acquisition of oil and natural gas properties:
	Proved	$–	$	$
			59,602	36,834
	Unproved	–	6,018	75,229
	Exploration costs	2,585	1,764	5,671
	Development costs	103,840	108,486	131,674
	Total	$	$	$
		106,425	175,870	249,408

Estimated_Proved_Oil_Natural_G1

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves (Tables)	12 Months Ended
	Dec. 31, 2014
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, 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
	Revisions of previous estimates (7)	-1,851	-138,666	-16,180	-246,856
	Purchases of minerals in place	21	1,515	222	2,974
	Extensions and discoveries (8)	1,900	81,571	5,767	127,571
	Production	-1,052	-43,363	-2,311	-63,540
	Sales of minerals in place	-194	-8,545	-257	-11,247
	As of December 31, 2014	11,908	712,192	36,143	1,000,496
	Proved developed reserves:
	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
	31-Dec-14	9,783	599,664	30,766	842,956
	Proved undeveloped reserves:
	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
	31-Dec-14	2,125	112,528	5,377	157,540
	_____________
	(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).
	(7)Revisions were primarily attributable to the removal of 213.3 Bcfe of reserves that we had planned to develop at December 31, 2013, but based on current prices, we no longer expect to develop within the next five years.
	(8)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 Bcfe).

Recovered_Sheet4

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, 2014
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:
		2014	2013	2012
	Future cash inflows	$	$	$
		4,639,547	4,998,790	4,005,432
	Future production and development costs	-2,123,559	-2,509,542	-1,971,099
	Future income tax expenses	-18,266	-22,091	-16,473
	Future net cash flows	2,497,722	2,467,157	2,017,860
	10% annual discount for estimated timing of cash flows	-1,404,419	-1,427,372	-1,150,928
	Standardized measure of discounted future net cash flows	$	$	$
		1,093,303	1,039,785	866,932
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:
		2014	2013	2012
	Standardized measure at beginning of period	$	$	$
		1,039,785	866,932	1,406,131
	Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	-216,972	-194,942	-167,233
	Net changes in prices and production costs	131,899	-1,264	-292,849
	Extensions, discoveries and improved recovery, less related costs	113,127	113,714	62,367
	Development costs incurred during the period	23,737	17,762	37,501
	Revisions and other	-69,407	53,427	-313,955
	Accretion of 10% timing discount	104,941	87,433	141,723
	Changes in income taxes	1,725	-2,218	3,697
	Changes in estimated future development costs	-2,980	1,692	1,319
	Changes in timing and other	-28,853	55,966	-35,046
	Purchase of minerals in place	4,376	41,810	32,906
	Sales of minerals in place	-8,075	-527	-9,629
	Standardized measure of discounted future net cash flows	$	$	$
		1,093,303	1,039,785	866,932

Organization_and_Nature_of_Bus1

Organization and Nature of Business (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
	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_Account1

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2015
Significant Accounting Policies [Line Items]
Capitalized costs associated with unproved properties	$117,700,000	$133,800,000
Dry hole and exploration costs	6,726,000	2,380,000	6,771,000
Impairment of oil and natural gas properties	113,968,000	85,341,000	34,453,000
Senior secured credit facility, maximum borrowing capacity	1,000,000,000
Subsequent Event [Member]
Significant Accounting Policies [Line Items]
Senior secured credit facility, maximum borrowing capacity				650,000,000
Proved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	103,300,000	76,900,000	32,400,000
Unproved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	$10,700,000	$8,500,000	$2,100,000
Customer Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration risk, number of clients	0	0	0
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	10.00%	10.00%	10.00%
Minimum [Member]
Significant Accounting Policies [Line Items]
Estimated economic lives of other property	3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Estimated economic lives of other property	25 years

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number 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
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
Compensation cost related to phantom or performance units recognized			0.2	2.5
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		11.9	8.5	4.8
Compensation cost related to phantom or performance units recognized		13.9	11.9	8.4
Unrecognized compensation cost related to unvested phantom units		24
Unrecognized compensation costs, weighted average period of recognition		2 years 9 months 18 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		1.4	1.6	1.7
Compensation cost related to phantom or performance units recognized		5.4	5.4	5.6
Unrecognized compensation cost related to unvested phantom units		$0.20

EquityBased_Compensation_Activ

Equity-Based Compensation (Activity Related To Units) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Awards [Member]
Number of Units
Nonvested phantom units as of December 31, 2013	922,756
Granted	358,100
Vested	-254,269
Forfeited	-38,262
Nonvested Phantom units as of December 31, 2014	988,325	922,756
Weighted Average Grant Date Fair Value per Phantom Unit
Nonvested phantom units as of December 31, 2013	$45.63
Granted	$22.77	$31.92	$58.92
Vested	$46.74
Forfeited	$47.24
Nonvested Phantom units as of December 31, 2014	$37	$45.63
Performance Units [Member]
Number of Units
Nonvested phantom units as of December 31, 2013	225,000
Vested	-22,500
Forfeited	-9,000
Nonvested Phantom units as of December 31, 2014	193,500
Weighted Average Grant Date Fair Value per Phantom Unit
Nonvested phantom units as of December 31, 2013	$64.07
Vested	$64.07
Forfeited	$64.07
Nonvested Phantom units as of December 31, 2014	$64.07

EquityBased_Compensation_Assum

Equity-Based Compensation (Assumptions Used To Estimate Weighted Average Fair Value) (Details) (Equity Awards [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$22.77	$31.92	$58.92
Expected volatility	34.52%	30.78%	37.87%
Risk-free interest rate	0.87%	0.68%	0.40%
Dividend yield	0.00%	0.00%	0.00%
Expected life (years)	4 years	4 years	4 years

Acquisitions_Narrative_Details

Acquisitions (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	31-May-12	Apr. 30, 2012	Mar. 31, 2013	Nov. 30, 2012	Feb. 29, 2012	Aug. 31, 2012
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price							$1,100,000
Oil, natural gas and natural gas liquids revenues	334,729,000	310,883,000	281,749,000
Mid-Continent Area [Member]
Business Acquisition [Line Items]
Amount paid in relation to final purchase price settlement				900,000
Barnett Shale [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired interest, percentage		31.00%						31.63%
Oil and natural gas properties acquired, purchase price		66,000,000						36,500,000
Oil, natural gas and natural gas liquids revenues		1,400,000
Amount received in relation to final purchase price settlement					1,700,000
Utica Shale [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price									75,200,000
Amount received in relation to final purchase price settlement						$8,000,000

Acquisitions_Recognized_Fair_V

Acquisitions (Recognized Fair Values of Identifiable Assets Acquired and Liabilities Assumed) (Details) (USD $)	Nov. 30, 2012	Dec. 31, 2013
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Business acquisition, assets acquired (liabilities assumed), net	$1,100
Business Acquisitions 2013 [Member]
Business Acquisition [Line Items]
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
Business acquisition, assets acquired (liabilities assumed), net		$65,974

Divestitures_Narrative_Details

Divestitures (Narrative) (Details) (USD $)	12 Months Ended				1 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and natural gas properties	$45,183,000		$44,056,000	$5,522,000
Proceeds from non-core oil and natural gas properties				500,000
Net income (loss)	109,660,000	[1]	5,125,000	-1,568,000
Asset sold, impairment charges			200,000
Assets and liabilities sold, previously held for sale	5,800,000
Burleson, Brazos and Grimes Counties in Texas [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	33,800,000
Cardinal Gas Services, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity method investment, ownership percentage	9.00%
Equity method investment, net sales proceeds	161,100,000
Net income (loss)	5,400,000		1,200,000	-100,000
Utica Shale [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	$5,600,000				$44,100,000
[1]	Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).

Investments_In_Unconsolidated_1

Investments In Unconsolidated Affiliates (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Net income (loss)	$109,660,000	[1]	$5,125,000	($1,568,000)
Utica East Ohio Midstream LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment amount exceeding equity	12,500,000
Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment amount exceeding equity			$8,200,000
[1]	Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).

Investments_In_Unconsolidated_2

Investments In Unconsolidated Affiliates (Summary of Financial Information for Unconsolidated Affiliates) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Revenues	$237,344	[1]	$56,888		$3,124
Operating income (loss)	109,003	[1]	4,955		-1,654
Net income (loss)	109,660	[1]	5,125		-1,568
Cardinal Gas Services LLC and Utica East Ohio Midstream LLC [Member]
Schedule of Equity Method Investments [Line Items]
Current assets	98,061	[2]	71,153	[3]
Noncurrent assets	1,381,773	[2]	1,528,518	[3]
Total assets	1,479,834	[2]	1,599,671	[3]
Current liabilities	37,967	[2]	145,006	[3]
Owner's equity	1,441,867	[2]	1,454,665	[3]
Total liabilities and owner's equity	$1,479,834	[2]	$1,599,671	[3]
[1]	Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).
[2]	Balance sheet information is for UEO on a stand-alone basis.
[3]	Balance sheet information is for UEO and Cardinal on a combined basis.

Risk_Management_Schedule_of_Co

Risk Management (Schedule of Commodity Contracts) (Details)	12 Months Ended
	Dec. 31, 2014
	MBbls
Oil [Member] | Swaps - 2015 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Oil, Hedged Volume	1,277.50
Weighted Average Fixed Price	90.28
Oil [Member] | Swaps - 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Oil, Hedged Volume	366
Weighted Average Fixed Price	90.14
Natural Gas [Member] | Swaps - 2015 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Natural Gas, Hedged Volume	39,602.50
Weighted Average Fixed Price	4.86
Natural Gas [Member] | Swaps - 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Natural Gas, Hedged Volume	18,300
Weighted Average Fixed Price	4.07

Risk_Management_Interest_Rate_

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

Risk_Management_Fair_Value_of_

Risk Management (Fair Value of Derivatives) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Asset:
Derivative asset, fair value	$135,401	$55,853
Derivative asset, liability	-1,710	-13,222
Derivative asset	113,044	13,543
Long-term derivative asset	20,647	29,088
Net recorded fair value	133,691	42,631
Derivative Liabilities:
Derivative liability, fair value	1,710	16,570
Derivative liability, asset	-1,710	-13,222
Derivative liability		3,348
Net recorded fair value		3,348
Derivative Asset [Member]
Derivative Asset:
Derivative asset, fair value	114,754	24,950
Derivative asset, liability	-1,710	-11,407
Derivative asset	113,044	13,543
Long-term Derivative Asset [Member]
Derivative Asset:
Derivative asset, fair value	20,647	30,903
Derivative asset, liability		-1,815
Long-term derivative asset	20,647	29,088
Derivative Liability [Member]
Derivative Liabilities:
Derivative liability, fair value	1,710	14,755
Derivative liability, asset	-1,710	-11,407
Derivative liability		3,348
Long-term Derivative Liability [Member]
Derivative Liabilities:
Derivative liability, fair value		1,815
Derivative liability, asset		-1,815
Long-term derivative liability

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$113,968,000	$85,341,000	$34,453,000
Asset retirement obligation	105,773,000	103,173,000	104,684,000
Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long lived assets held for sale, carrying value		8,000,000
8.0% Senior Notes due 2019 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes, fair value	427,500,000	504,700,000
Senior notes, carrying value	499,400,000	499,300,000	499,300,000
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	186,100,000	131,500,000	66,100,000
Impairment of oil and natural gas properties	103,100,000	76,300,000	31,900,000
Oil and natural gas properties, fair value	83,000,000	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	6,000,000
Impairment of oil and natural gas properties	200,000	500,000	500,000
Oil and natural gas properties, fair value	5,800,000	8,000,000	6,000,000
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, 2014	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	$135,401	$55,853
Derivative liability, fair value	1,710	16,570
Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability, fair value		16,570
Recurring Basis [Member] | Commodity Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	135,401	55,853
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	1,710		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
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	135,401	55,853
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	1,710		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, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets	$88,844	$63,175	$40,228
Total losses	103,282	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	5,801	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	83,043	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	83,043	55,163	34,214
Total losses	103,118	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	83,043	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	5,801	8,012	6,014
Total losses	164	514	491
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	$5,801	$8,012	$6,014

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Asset retirement obligation, current	$1,941	$1,885
Asset retirement obligation	105,773	103,173	104,684
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Abstract]
Balance at beginning of period	$103,173	$104,684
Liabilities incurred and assumed in acquisitions	753	1,852
Accretion expense	4,835	4,925	5,116
Revisions in estimated cash flows	432	-6,704
Settlements and divestitures	-3,420	-1,584
Balance at end of period	$105,773	$103,173	$104,684

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	$1,000,000,000
Senior secured credit facility, expiration date	30-Apr-16
Debt instrument, covenant compliance, credit facility and letters of credit	we were in compliance with these financial covenants
Weighted average effective interest rate	2.98%	3.09%
Line of credit, borrowing base	730,000,000
Credit facility outstanding	531,000,000	481,000,000
Senior unsecured notes, offering price			206,000,000
Minimum [Member]
Debt Instrument [Line Items]
Current ratio required under credit facility	1
Total debt to earnings ratio required under credit facility	1
Maximum [Member]
Debt Instrument [Line Items]
Total debt to earnings ratio required under credit facility	3.5
Borrowing Base Determination, Period One [Member]
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date	3
Borrowing Base Determination, Period Two [Member]
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date	9
8.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Senior notes	500,000,000
Senior unsecured notes, stated interest rate	8.00%
Senior unsecured notes, maturity date	2019
Redemption price if change of control occurs	101.00%
Senior notes, carrying value	499,400,000	499,300,000	499,300,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	$100,000,000

LongTerm_Debt_Redemption_Price

Long-Term Debt (Redemption Prices On Applicable Redemption Dates) (Details)	Dec. 31, 2014
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%

Recovered_Sheet5

Commitments and Contingencies (Narrative) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Minimum [Member]
Construction funding commitment, 2015	$26
Maximum [Member]
Construction funding commitment, 2015	$32

Commitments_and_Contingencies_1

Commitments and Contingencies (Schedule of Future Minimum Transportation Fees Payment) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments and Contingencies [Abstract]
2015	$618
2016	619
2017	618
2018	619
2019	618
Thereafter	1,650
Balance as of December 31, 2014	$4,742

Owners_Equity_Narrative_Detail

Owners' Equity (Narrative) (Details) (USD $)	1 Months Ended		12 Months Ended			0 Months Ended
	Oct. 31, 2013	Feb. 29, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 13, 2015	Feb. 02, 2015
Stockholders Equity Note [Line Items]
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
Public offering, price per common units	$36.86	$67.95
Net proceeds from public offerings, including contributions	$208,500,000	$267,900,000		$204,527,000	$262,833,000
Contribution from general partner	4,200,000	5,400,000	154,000	4,508,000	5,714,000
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%
Dividend Declared [Member]
Stockholders Equity Note [Line Items]
Distribution to unitholders, declared date			2-Feb-15
Distribution to unitholders declared per unit							$0.50
Distribution to unitholders, amount						$25,200,000
Distribution to unitholders, record date							9-Feb-15
Distribution to unitholders, payment date							13-Feb-15
Executive Officers and Directors [Member]
Stockholders Equity Note [Line Items]
Common unitholders, units outstanding			4,249,470
Common Unitholders [Member]
Stockholders Equity Note [Line Items]
Common unitholders, units issued			48,572,019	48,349,080
Common unitholders, units outstanding			48,572,019	48,349,080

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, 2014
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			3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Mar. 31, 2014	Jun. 30, 2014	Sep. 30, 2014	Dec. 31, 2012	Mar. 31, 2013
Distribution Made to Limited Partner [Line Items]
Total Distribution	$154,978	$140,126	$128,924
Cash Distributions Period Covered October 1, 2013 - December 31, 2013 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid				14-Feb-14
Distribution per Unit				$0.77
Total Distribution				38,696
Cash Distributions Period Covered January 1, 2014 - March 31, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid					15-May-14
Distribution per Unit					$0.77
Total Distribution					38,716
Cash Distributions Period Covered April 1, 2014 - June 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid						14-Aug-14
Distribution per Unit						$0.77
Total Distribution						38,760
Cash Distributions Period Covered July 1, 2014 - September 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid							14-Nov-14
Distribution per Unit							$0.77
Total Distribution							38,806
Cash Distributions Period Covered October 1, 2012 - 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 - 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 - 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 - 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

Net_Income_Loss_Per_Limited_Pa2

Net Income (Loss) 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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share Disclosure [Line Items]
Net (loss) income	$102,376	$42,620	($9,023)	($6,253)	($50,186)	($12,314)	$32,854	($46,581)	$129,720		($76,227)		($16,349)
General partner interest in the partnership, percentage									2.00%
Net (loss) income attributable to participating securities									-1,723		-2,006
Limited partners' interest in net (loss) income									125,402		-76,708		-16,022
Weighted average limited partner units outstanding:
Denominator for basic net income (loss) per limited partner unit									48,563,000		43,691,000		41,952,000
Dilutive phantom units										[1]		[1]		[1]
Total									48,563,000		43,691,000		41,952,000
Net (loss) income per limited partner unit:
Basic	$2.03	$0.85	($0.19)	($0.14)	($1.06)	($0.29)	$0.74	($1.08)	$2.58		($1.76)		($0.38)
Diluted	$2.03	$0.85	($0.19)	($0.14)	($1.06)	($0.29)	$0.74	($1.08)	$2.58		($1.76)		($0.38)
Equity awards not included in the computation of diluted net (loss) income per limited partner									200,000		200,000		800,000
General Partner Interests [Member]
Earnings Per Share Disclosure [Line Items]
Net income available for general partners									-2,595		1,525		327
Common Units [Member]
Weighted average limited partner units outstanding:
Denominator for basic net income (loss) per limited partner unit									48,563,000		43,691,000		38,156,000
Class B Unitholders [Member]
Earnings Per Share Disclosure [Line Items]
Net (loss) income													($1,160)
Weighted average limited partner units outstanding:
Denominator for basic net income (loss) per limited partner unit													3,662,000
Performance Units [Member]
Weighted average limited partner units outstanding:
Denominator for basic net income (loss) per limited partner unit													134,000
[1]	Unearned performance units totaling 0.2 million, 0.2 million and 0.8 million units were not included in the computation of diluted net income (loss) per limited partner unit for 2014, 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
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Equity in (loss) income of unconsolidated affiliates	$15,762,000	($344,000)	$18,000
Dividends from unconsolidated affiliates	337,000	285,000	79,000
EnerVest, Ltd. [Member]
Related Party Transaction [Line Items]
Administrative fees paid to related party	12,100,000	10,000,000	13,100,000
Direct expenses incurred and reimbursed to related party	17,000,000	17,100,000	17,500,000
Overriding Royalty Interests [Member]
Related Party Transaction [Line Items]
Percentage of overriding royalty interest carved out				7.50%
Percentage of limited partnership interest				48.00%
Percentage of gross revenues to be received				5.64%
Equity in (loss) income of unconsolidated affiliates	400,000	200,000	100,000
Dividends from unconsolidated affiliates	$300,000	$200,000

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental cash flows information:
Cash paid for interest	$49,444	$45,355	$47,903
Cash paid for income taxes	155	325	340
Capitalized interest	5,741	7,276	906
Non-cash transactions:
Costs for additions to oil and natural gas properties	18,028	19,450	13,951
Purchase price adjustment in accounts receivable			$7,969

Other_Supplemental_Information3

Other Supplemental Information (Schedule of Accounts Payable and Accrued Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Supplemental Information [Abstract]
Costs for additions to oil and natural gas properties	$18,028	$19,450
Lease operating expenses	9,701	7,793
Interest	8,649	8,701
Production and ad valorem taxes	5,683	4,862
General and administrative expenses	2,317	2,082
Current portion of ARO	1,941	1,885
Derivative settlements	280	1,443
Other	1,279	660
Total	$47,878	$46,876

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, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Data [Abstract]
Revenues	$70,175		$84,531		$89,360		$95,339		$78,594		$81,414		$81,602		$73,702		$339,405	$315,312	$285,480
Gross profit	39,126	[1]	54,105	[1]	59,433	[1]	65,451	[1]	49,144	[1]	51,526	[1]	51,510	[1]	43,949	[1]
Net (loss) income	102,376		42,620		-9,023		-6,253		-50,186		-12,314		32,854		-46,581		129,720	-76,227	-16,349
Limited partners' interest in net income (loss)																	$125,402	($76,708)	($16,022)
Net (loss) income per limited partner unit:
Basic	$2.03		$0.85		($0.19)		($0.14)		($1.06)		($0.29)		$0.74		($1.08)		$2.58	($1.76)	($0.38)
Diluted	$2.03		$0.85		($0.19)		($0.14)		($1.06)		($0.29)		$0.74		($1.08)		$2.58	($1.76)	($0.38)
[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, 2014
	segment
Segment Information [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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total revenues	$70,175	$84,531	$89,360	$95,339	$78,594	$81,414	$81,602	$73,702	$339,405	$315,312	$285,480
Segment profit									211,389	193,749	161,593
Equity in (loss) income of unconsolidated affiliates									15,762	-344	18
Capital expenditures									112,409	175,870
Assets	2,249,203				2,204,983				2,249,203	2,204,983
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total revenues									339,405	315,312	285,480
Segment profit									211,389	193,749	161,593
Equity in (loss) income of unconsolidated affiliates									408	259	156
Capital expenditures									112,409	175,870
Assets	1,934,030				1,950,300				1,934,030	1,950,300
Midstream [Member]
Segment Reporting Information [Line Items]
Equity in (loss) income of unconsolidated affiliates									15,354	-603	-138
Assets	$315,173				$254,683				$315,173	$254,683

Segment_Information_Reconcilia

Segment Information (Reconciliation of Segment Profits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Information [Abstract]
Segment profit	$211,389	$193,749	$161,593
Asset retirement obligations accretion expense	-4,835	-4,925	-5,116
Depreciation, depletion and amortization	-106,073	-113,818	-113,381
General and administrative expenses	-44,955	-40,677	-42,682
Impairment of oil and natural gas properties	-113,968	-85,341	-34,453
Gain on sales of oil and natural gas properties	33,319	41,309
Gain (loss) on derivatives, net	99,720	-17,262	66,734
Interest expense	-52,578	-49,062	-48,689
Gain on sale of investment in unconsolidated affiliate	92,121
Other income	294	277	705
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	$114,434	($75,750)	($15,289)

Supplementary_Information_on_O1

Supplementary Information on Oil and Natural Gas Activities (Capitalized Costs Relating to Oil and Natural Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Supplementary Information On Oil And Natural Gas Activities [Abstract]
Proved oil and natural gas properties	$2,371,866	$2,265,069
Unproved oil and natural gas properties	117,738	133,763
Total oil and natural gas properties	2,489,604	2,398,832
Accumulated depreciation, depletion and amortization	-778,679	-569,770
Net capitalized costs	$1,710,925	$1,829,062

Supplementary_Information_on_O2

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Acquisition of oil and natural gas properties:
Proved		$59,602	$36,834
Unproved		6,018	75,229
Exploration costs	2,585	1,764	5,671
Development costs	103,840	108,486	131,674
Total	$106,425	$175,870	$249,408

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
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	Mcfe		Mcfe		Mcfe		Mcfe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	1,191,594,000	[1]	904,669,000	[1]	1,144,389,000	[1]
Revisions of previous estimates	-246,856,000	[1],[2]	60,663,000	[1],[3]	-253,513,000	[1]
Purchase of minerals in place	2,974,000	[1]	70,395,000	[1]	30,301,000	[1]
Extensions and discoveries	127,571,000	[1],[4],[5]	218,112,000	[1],[6]	47,649,000	[1]
Production	-63,540,000	[1]	-61,690,000	[1]	-59,647,000	[1]
Sales of minerals in place	-11,247,000	[1]	-555,000	[1]	-4,510,000	[1]
Proved developed and undeveloped reserves, ending balance	1,000,496,000	[1]	1,191,594,000	[1]	904,669,000	[1]
Oil and natural gas reserves					269,900,000
Oil and natural gas reserves offset by positive development and production history					16,400,000
Reduction [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves			213,300,000
Proved Developed Reserves [Member
Reserve Quantities [Line Items]
Proved developed reserves (energy)	842,956,000	[1]	815,268,000	[1]	689,133,000	[1]	779,693,000	[1]
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (energy)	157,540,000	[1]	376,326,000	[1]	215,536,000	[1]	364,696,000	[1]
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	13,084	[7]	13,508	[7]	15,067	[7]
Revisions of previous estimates	-1,851	[2],[7]	-760	[3],[7]	-1,489	[7]
Purchases of minerals in place	21	[7]	21	[7]	236	[7]
Extensions and discoveries	1,900	[4],[5],[7]	1,342	[6],[7]	1,011	[7]
Production	-1,052	[7]	-1,027	[7]	-1,110	[7]
Sales of minerals in place	-194	[7]			-207	[7]
Proved developed and undeveloped reserves, ending balance	11,908	[7]	13,084	[7]	13,508	[7]
Oil [Member] | Proved Developed Reserves [Member
Reserve Quantities [Line Items]
Proved developed reserves (volume)	9,783	[7]	10,443	[7]	11,153	[7]	11,675	[7]
Oil [Member] | Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	2,125	[7]	2,641	[7]
Proved undeveloped reserve (volume)					2,355	[7]	3,392	[7]
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	819,680	[8]	609,546	[8]	808,681	[8]
Revisions of previous estimates	-138,666	[2],[8]	36,214	[3],[8]	-210,452	[8]
Purchases of minerals in place	1,515	[8]	67,291	[8]	25,532	[8]
Extensions and discoveries	81,571	[4],[5],[8]	149,502	[6],[8]	30,429	[8]
Production	-43,363	[8]	-42,651	[8]	-42,536	[8]
Sales of minerals in place	-8,545	[8]	-222	[8]	-2,108	[8]
Proved developed and undeveloped reserves, ending balance	712,192	[8]	819,680	[8]	609,546	[8]
Natural Gas [Member] | Proved Developed Reserves [Member
Reserve Quantities [Line Items]
Proved developed reserves (volume)	599,664	[8]	578,274	[8]	473,223	[8]	557,489	[8]
Natural Gas [Member] | Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	112,528	[8]	241,406	[8]
Proved undeveloped reserve (volume)					136,323	[8]	251,192	[8]
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	48,902	[7]	35,679	[7]	40,884	[7]
Revisions of previous estimates	-16,180	[2],[7]	4,835	[3],[7]	-5,688	[7]
Purchases of minerals in place	222	[7]	496	[7]	559	[7]
Extensions and discoveries	5,767	[4],[5],[7]	10,093	[6],[7]	1,859	[7]
Production	-2,311	[7]	-2,146	[7]	-1,742	[7]
Sales of minerals in place	-257	[7]	-55	[7]	-193	[7]
Proved developed and undeveloped reserves, ending balance	36,143	[7]	48,902	[7]	35,679	[7]
Natural Gas Liquids [Member] | Proved Developed Reserves [Member
Reserve Quantities [Line Items]
Proved developed reserves (volume)	30,766	[7]	29,056	[7]	24,832	[7]	25,359	[7]
Natural Gas Liquids [Member] | Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	5,377	[7]	19,846	[7]
Proved undeveloped reserve (volume)					10,847	[7]	15,525	[7]
Barnett Shale [Member]
Reserve Quantities [Line Items]
Volume produced from oil drilling success	78,200,000		177,100,000		39,000,000
Appalachian Basin [Member]
Reserve Quantities [Line Items]
Volume produced from oil drilling success	33,000,000				3,100,000
[1]	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
[2]	Revisions were primarily attributable to the removal of 213.3 Bcfe of reserves that we had planned to develop at December 31, 2013, but based on current prices, we no longer expect to develop within the next five years.
[3]	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).
[4]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (177.1 Bcfe).
[5]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 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).
[7]	Thousands of barrels.
[8]	Million cubic feet.

Standardized_Measure_of_Discon1

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, 2014	Dec. 31, 2013	Dec. 31, 2012
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	94.99	96.78	94.71
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	4.35	3.666	2.757

Standardized_Measure_of_Discon2

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 $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Standardized Measure of Discontinued Future Net Cash Flows Relating to Proved Oil, Natural Gas and Natural Gas Liquids Reserves [Abstract]
Future cash inflows	$4,639,547	$4,998,790	$4,005,432
Future production and development costs	-2,123,559	-2,509,542	-1,971,099
Future income tax expenses	-18,266	-22,091	-16,473
Future net cash flows	2,497,722	2,467,157	2,017,860
10% annual discount for estimated timing of cash flows	-1,404,419	-1,427,372	-1,150,928
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$1,093,303	$1,039,785	$866,932	$1,406,131
Future net cash flows, annual discount rate	10.00%

Standardized_Measure_of_Discon3

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, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$1,039,785	$866,932	$1,406,131
Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	-216,972	-194,942	-167,233
Net changes in prices and production costs	131,899	-1,264	-292,849
Extensions, discoveries and improved recovery, less related costs	113,127	113,714	62,367
Development costs incurred during the period	23,737	17,762	37,501
Revisions and other	-69,407	53,427	-313,955
Accretion of 10% timing discount	104,941	87,433	141,723
Changes in income taxes	1,725	-2,218	3,697
Changes in estimated future development costs	-2,980	1,692	1,319
Changes in timing and other	-28,853	55,966	-35,046
Purchase of minerals in place	4,376	41,810	32,906
Sales of minerals in place	-8,075	-527	-9,629
Standardized measure of discounted future net cash flows	$1,093,303	$1,039,785	$866,932
Accretion timing discount rate	10.00%	10.00%	10.00%