Harvest Oil & Gas (HRST) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	evep
Entity Registrant Name	EV Energy Partners, LP
Entity Central Index Key	1,361,937
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		49,055,214
Entity Public Float			$ 503,090,238

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 20,415	$ 8,255
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	24,285	32,758
Related party		1,043
Other	7,137	4,570
Derivative asset	60,662	113,044
Other current assets	3,057	2,000
Assets held for sale		315,173
Total current assets	115,556	476,843
Oil and natural gas properties, net of accumulated depreciation, depletion and December 31, 2015, $971,499; December 31, 2014, $778,679	1,790,455	1,710,925
Other property, net of accumulated depreciation and amortization; December 31, 2015, $970; December 31, 2014, $898	1,019	1,141
Restricted cash		33,768
Long-term derivative asset	10,741	20,647
Other assets	5,831	2,837
Total assets	1,923,602	2,246,161
Current liabilities:
Accounts payable and accrued liabilities	43,135	47,878
Related party	5,952
Income taxes	11,657
Total current liabilities	60,744	47,878
Asset retirement obligations	174,003	103,832
Long-term debt, net	688,614	1,027,349
Other long-term liabilities	$ 1,682	$ 989
Commitments and contingencies
Owners' equity:
Common unitholders - 48,871,399 units and 48,572,019 units issued and as of December 31, 2015 and 2014, respectively	$ 1,011,509	$ 1,077,826
General partner interest	(12,950)	(11,713)
Total owners' equity	998,559	1,066,113
Total liabilities and owners' equity	$ 1,923,602	$ 2,246,161

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and natural gas properties, accumulated depreciation, depletion and amortization	$ 971,499	$ 778,679
Other property, accumulated depreciation and amortization	$ 970	$ 898
Common Unitholders [Member]
Common unitholders, units issued	48,871,399	48,572,019
Common unitholders, units outstanding	48,871,399

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil, natural gas and natural gas liquids revenues	$ 175,088	$ 334,729	$ 310,883
Transportation and marketing-related revenues	2,883	4,676	4,429
Total revenues	177,971	339,405	315,312
Operating costs and expenses:
Lease operating expenses	99,626	105,781	104,465
Cost of purchased natural gas	1,988	3,533	3,242
Dry hole and exploration costs	3,695	6,726	2,380
Production taxes	6,784	11,976	11,476
Accretion expense on obligations	5,598	4,835	4,925
Depreciation, depletion and amortization	105,969	106,073	113,818
General and administrative expenses	38,994	44,955	40,677
Impairment of oil and natural gas properties	136,667	113,968	85,341
Impairment of goodwill	65,924
Loss on settlement of contract	1,210
Gain on sales of oil and natural gas properties	(551)	(33,319)	(41,309)
Total operating costs and expenses	465,904	364,528	325,015
Operating loss	(287,933)	(25,123)	(9,703)
Other income (expense), net:
Gain (loss) on derivatives, net	78,145	99,720	(17,262)
Interest expense	(50,336)	(52,578)	(49,062)
Gain on early extinguishment of debt	24,024
Other income, net	78	702	536
Total other income (expense), net	51,911	47,844	(65,788)
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	(236,022)	22,721	(75,491)
Income taxes	1,843	(476)	(133)
(Loss) income from continuing operations	(234,179)	22,245	(75,624)
Income (loss) from discontinued operations	255,512	107,475	(603)
Net (loss) income	$ 21,333	$ 129,720	$ (76,227)
Earnings per limited partner unit (basic and diluted):
(Loss) income from continuing operations	$ (4.72)	$ 0.41	$ (1.75)
Income (loss) from discontinued operations	5.13	2.17	(0.01)
Net income (loss)	$ 0.41	$ 2.58	$ (1.76)
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding (basic and diluted)	48,853	48,563	43,691
Distributions declared per common unit	$ 1.575	$ 2.819	$ 3.078

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ 21,333	$ 129,720	$ (76,227)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
(Income) loss from discontinued operations	(255,512)	(107,475)	603
Accretion expense on obligations	5,598	4,835	4,925
Amortization of volumetric production payment liability	(1,196)
Depreciation, depletion and amortization	105,969	106,073	113,818
Equity-based compensation	12,001	19,289	17,470
Impairment of oil and natural gas properties	136,667	113,968	85,341
Impairment of goodwill	65,924
Gain on sales of oil and natural gas properties	(551)	(33,319)	(41,309)
(Gain) loss on derivatives, net	(78,145)	(99,720)	17,262
Cash settlements of matured derivative contracts	140,657	5,313	30,066
Gain on early extinguishment of debt	(24,024)
Deferred taxes	(13,285)
Other	4,487	5,703	2,679
Changes in operating assets and liabilities: , net of effects of amounts acquired:
Accounts receivable	14,850	3,275	(2,671)
Other current assets	511	(1,203)	(68)
Accounts payable and accrued liabilities	(4,067)	2,368	1,316
Income taxes	10,683
Other, net	(245)	(627)	(706)
Net cash flows provided from operating activities from continuing operations	141,655	148,200	152,499
Net cash flows used in operating activities from discontinued operations	(372)
Net cash flows provided by operating activities	141,283	148,200	152,499
Cash flows from investing activities:
Acquisitions of oil and natural gas properties net of cash acquired	(250,357)		(57,976)
Additions to oil and natural gas properties	(67,923)	(102,761)	(97,946)
Prepaid drilling costs		(2,501)	(5,041)
Proceeds from sale of oil and natural gas properties	1,457	45,183	44,056
Restricted cash	33,768	(33,768)
Cash settlements from acquired derivative contracts	2,615
Other	73	48	38
Net cash flows used in investing activities from continuing operations	(280,367)	(93,799)	(116,869)
Net cash flows provided by (used in) investing activities from discontinued operations	572,160	46,985	(221,101)
Net cash flows provided by (used in) investing activities	291,793	(46,814)	(337,970)
Cash flows from financing activities:
Long-term debt borrowings	295,000	209,000	329,000
Repayments of long-term debt borrowings	(561,000)	(159,000)	(208,000)
Redemption of 8% Senior Notes due 2019	(49,954)
Loan costs paid	(4,074)
Proceeds from public equity offerings			204,527
Offering costs			(226)
Contributions from general partner	91	154	4,508
Distributions paid	(100,979)	(154,978)	(140,126)
Other		(5)
Net cash flows (used in) provided by financing activities	(420,916)	(104,829)	189,683
Increase (decrease) in cash and cash equivalents	12,160	(3,443)	4,212
Cash and cash equivalents - beginning of year	8,255	11,698	7,486
Cash and cash equivalents - end of year	$ 20,415	$ 8,255	$ 11,698

Consolidated Statements of Chan

Consolidated Statements of Changes in Owners' Equity - USD ($) $ in Thousands	Common Unitholders [Member]	General Partner Interest [Member]	Total
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 income (loss)	(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 income (loss)	127,125	2,595	129,720
Balance at Dec. 31, 2014	1,077,826	(11,713)	1,066,113
Contributions from general partner		91	91
Distributions paid	(98,985)	(1,994)	(100,979)
Equity-based compensation	11,761	240	12,001
Net income (loss)	20,907	426	21,333
Balance at Dec. 31, 2015	$ 1,011,509	$ (12,950)	$ 998,559

Consolidated Statements of Cha7

Consolidated Statements of Changes in Owners' Equity (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)shares
Consolidated Statements of Changes in Owners' Equity [Abstract]
Conversion of vested phantom units, units | shares	40,264
Proceeds from public equity offerings, offering costs | $	$ 226

Organization and Nature of Busi

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2015
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. With the sale of the Partnership’s interest in Cardinal Gas Services, LLC (“Cardinal”) in October 2014 and the sale of its interest in Utica East Ohio Midstream LLC (“UEO”) in June 2015, the Partnership no longer operates in the midstream segment, and the Partnership has reclassified its consolidated financial statements for all periods presented to reflect the operations of its midstream segment as discontinued operations (see Note 13). Accordingly, in the consolidated balance sheets, amounts previously included in “Investments in unconsolidated affiliates” have been reclassified to ”Assets held for sale” and, in the consolidated statements of operations, amounts previously included in “Equity in income of unconsolidated affiliates” have been reclassified to “Income from discontinued operations.” The Partnership now operates in one reportable segment engaged in the acquisition, development and production of oil and natural gas properties and all of our operations are located in the United States.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 units, 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, 2015 and 2014, 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 $ 67.6 million and $ 117.7 million as of December 31, 2015 and December 31, 2014, 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 2015, 2014 and 2013, we recorded dry hole and exploration costs of $ 3.7 million, $ 6.7 million and $ 2.4 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 Oil and Natural Gas Properties 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 2015, 2014 and 2013, we recorded impairment charges of $86.9 million, $ 103.3 million and $ 76.9 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 7). Since December 31, 2015, commodity prices have continued to deteriorate. If commodity prices do not improve before March 31, 2016, we anticipate additional impairments of our oil and natural gas properties. Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized. For 2015, 2014 and 2013, we recorded impairment charges of $49.8 million, $ 10.7 million and $ 8.5 million, respectively, related to unproved oil and natural gas properties where we had a change in development plans for the acreage. Goodwill We recorded $65.9 million of goodwill in conjunction with our October 2015 acquisitions (see Note 4). Goodwill was calculated as the excess of the purchase price over the estimated fair values of the assets acquired net of the liabilities assumed in the acquisitions. The goodwill was not amortized, but was evaluated for impairment as the declining oil and natural price environment indicated the carrying value of goodwill may not be recoverable (see Note 7). The changes in the carrying amount of goodwill are as follows: Balance as of December 31, 2014 $ - Goodwill acquired during the year 65,924 Impairment losses (65,924) Balance as of December 31, 2015 $ - 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. 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, 2015 or 2014. We own and operate a network of natural gas gathering systems in the Appalachian Basin and 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. In October 2015, we acquired Belden & Blake Corporation (“Belden”), a taxable entity (see Note 4). We used the asset and liability method of accounting for income taxes. Under this method, deferred taxes were provided for temporary differences as of the date of acquisition between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In December 2015, Belden was converted from a corporation into a single member limited liability company (see Note 12). Earnings per Limited Partner Unit We use the two–class method to compute earnings per limited partner unit. The two-class method is an earnings allocation formula that determines earnings per unit for our common units and participating securities as if all earnings for the period had been distributed. As our unvested phantom units and our earned but unvested performance units participate in dividends on an equal basis with our common units, they are considered to be participating securities. Earnings used in the determination of earnings per limited partner unit for the current reporting period are reduced by the amount of earnings allocated to the general partner and available cash that will be distributed to the limited partners and the participating securities. The undistributed earnings, if any, are then allocated to the limited partners and the participating securities in accordance with the terms of the partnership agreement. Basic and diluted earnings per limited partner unit are then calculated by dividing earnings, after deducting the amount allocated to the general partner and the earnings attributable to the participating securities, 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, 2015, 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 2015, two customers accounted for 17.1% and 10.8% , respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2014 and 2013, 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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09, Revenue from Contracts with Customers. This ASU superseded 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. In August 2015, the FASB issued ASU 2015–14 that deferred the adoption of ASU 2014–09 for one year. The provisions of ASU 2014–09 are now applicable to annual reporting periods beginning after December 15, 2017 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 April 2015, the FASB issued ASU No. 2015–03, Interest – Imputation of Interest . This ASU changes the presentation of debt issuance costs in financial statements. Under ASU 2015–03, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. As the guidance in this ASU did not address presentation or subsequent measurement of debt issuance costs related to line–of–credit arrangements, the FASB issued ASU 2015–15, Interest – Imputation of Interest, in August 2015 to clarify that these presentation requirements did not apply to line–of–credit arrangements. We adopted ASU 2015–03 and ASU 2015–15 on December 31, 2015, which required that we apply the guidance on a retrospective basis, wherein our consolidated balance sheets for all periods presented were adjusted to reflect the effects of applying the guidance. Accordingly, as of December 31, 2014, we reclassified $ 3.0 million of debt issuance costs previously reported in “Other assets” to “Long–term debt , net” on our consolidated balance sheet. In addition, as of December 31, 2015, we presented $ 2.0 million of debt issuance costs as a reduction of long–term debt on our consolidated balance sheet. In April 2015, the FASB issued ASU No. 2015–06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions . ASU 2015–06 specifies that for purposes of calculating historical earnings per unit under the two class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In addition, qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two class method are also required. The provisions of ASU 2015–06 are applicable to annual reporting periods beginning after December 15, 2015 and interim periods within those annual periods. We will adopt this ASU should we enter into a dropdown transaction. In September 2015, the FASB issued ASU 2015–16, Simplifying the Accounting for Measurement Period Adjustments. To simplify the accounting for adjustments made to provisional amounts, ASU 2015–16 requires that the acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amount is determined. The provisions of ASU 2015–16 are effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. We will adopt this ASU should we report provisional amounts for items in a business combination. No other new accounting pronouncements issued or effective during the year ended December 31, 2015 have had or are expected to have a material impact on our consolidated financial statements. Subsequent Events We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2015
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, 2015, 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: 2015 2014 2013 Weighted average fair value of phantom units $ 2.61 $ 22.77 $ 31.92 Expected volatility 62.33% 34.52% 30.78% Risk–free interest rate 1.13% 0.87% 0.68% Dividend yield 0.0% 0.0% 0.0% Expected life (years) 4.1 4.0 4.0 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: Number Weighted Average of Grant Date Phantom Units Fair Value Nonvested phantom units as of December 31, 2014 988,325 $ 37.00 Granted 1,088,303 2.61 Vested (338,661) 44.93 Forfeited (48,719) 32.25 Nonvested phantom units as of December 31, 2015 1,689,248 $ 13.39 The total grant date fair value of the phantom units vested in 2015, 2014 and 2013 was $ 15.2 million, $ 11.9 million and $ 8.5 million, respectively. We recognized compensation cost related to these phantom units of $ 11.8 million, $ 13.9 million and $ 11.9 million in 2015, 2014 and 2013. These costs are included in “General and administrative expenses” in our consolidated statements of operations. As of December 31, 2015, there was $ 14.7 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2. 5 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 was $2.4 million, and we recognized compensation cost related to these phantom units of $0.2 million in 2013. 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 vested 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: Number of Weighted Average Performance Grant Date Units Fair Value Nonvested performance units as of December 31, 2014 193,500 $ 64.07 Vested (21,500) 73.78 Forfeited (172,000) 59.21 Nonvested performance units as of December 31, 2015 - $ - The total grant date fair value of the performance units vested in 2015, 2014 and 2013 was $ 1.6 million, $ 1.4 million and $ 1.6 million, respectively. We recognized compensation cost related to our performance units of $0.2 million, $ 5.4 million and $ 5.4 million in 2015, 2014 and 2013, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Acquisitions [Abstract]
Acquisitions	NOTE 4. ACQUISITIONS 2015 In October 2015, we made the following acquisitions from certain institutional partnerships managed by EverVest , a related party : · we acquired Belden for $111.1 million , and w e recognized $5.6 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations f or 2015; · we acquired oil and natural gas properties in the Austin Chalk for $25.9 million, and we recognized $4.9 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations f or 2015; and · we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million , and w e recognized $4.5 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations f or 2015. These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties. As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements. Under these agreements, certain of these oil and natural gas properties are subject to fixed–term overriding royalty interests which had been conveyed to the VPP purchaser. While we are obligated under these agreements to produce and deliver to the purchaser its portion of future natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling. If production from the oil and natural gas properties subject to the VPP is inadequate to deliver the natural gas provided for in the VPP, we ha ve an obligation to make up the shortfall in accordance with the provisions of the agreements. At December 31, 2015, the remaining obligation under these agreements was approximately 1.9 Bcf of natural gas, and we have a liability of $4.0 million for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. In 2015, we recorded $0.1 million of accretion expense related to this VPP obligation . We accounted for th ese acquisition s as business combination s . The following table reflects pro forma revenues and net income for the years ended December 31 , 2015 and 2014 as if these acquisitions had taken place on January 1, 2014. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future. 2015 2014 Revenues: Historical $ 177,971 $ 339,405 Belden 24,292 65,453 Austin Chalk 9,235 24,074 Appalachian and San Juan Basins 23,738 59,490 Pro forma revenues $ 235,236 $ 488,422 Net income (loss): Historical $ 21,333 $ 129,720 Belden (76,910) (1,794) Austin Chalk 1,217 11,395 Appalachian and San Juan Basins 414 19,380 Pro forma net income $ (53,946) $ 158,701 The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with these acquisitions are as follows: Appalachian and San Juan Belden Austin Chalk Basins Total Cash $ 8,665 $ - $ - $ 8,665 Accounts receivable 7,901 - - 7,901 Derivative asset 2,711 - - 2,711 Other current assets 1,053 318 1,318 2,689 Proved oil and natural gas properties 105,626 28,513 136,176 270,315 Unproved oil and natural gas properties - 1,020 - 1,020 Goodwill 45,681 - 20,243 65,924 Long-term derivative assets 128 - - 128 Other assets 1,150 - - 1,150 Accounts payable and accrued liabilities (11,308) (256) (5,456) (17,020) Income taxes (974) - - (974) Deferred taxes (13,409) - - (13,409) Asset retirement obligations (35,551) (3,698) (30,260) (69,509) Other long-term liabilities (569) - - (569) $ 111,104 $ 25,897 $ 122,021 $ 259,022 The amounts allocated to goodwill represent the future benefits arising from acquiring these assets from EnerVest, which has experience operating these properties, and from adding balance to our existing portfolio by increasing our positions in the Appalachian Basin, Michigan, the San Juan Basin and the Austin Chalk. Of the $65.9 million allocated to goodwill, $20.2 of the amount will be deductible for income tax purposes. The amounts included in the table above are preliminary with respect to accruals and working capital adjustments and include the use of estimates based on information that was available at the time these audited consolidated financial statements were prepared. We believe that the estimates used are reasonable; however, the estimates are subject to change as additional information becomes available. 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. 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.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2015
Divestitures [Abstract]
Divestitures	NOTE 5. DIVESTITURES 2015 In 2015, we closed on the sale of non–core oil and natural gas properties for aggregate proceeds of $ 1.5 million. 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. We sold oil and natural gas properties in East Texas 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 .

Risk Management

Risk Management	12 Months Ended
	Dec. 31, 2015
Risk Management [Abstract]
Risk Management	NOTE 6. 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, c hanges 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, 2015, we had entered into oil, natural gas and natural gas liquids derivatives with the following terms: Weighted Average Hedged Fixed Period Covered Volume Price Oil (MBbls): Swaps – 2016 366.0 $ 90.14 Natural Gas (MmmBtus): Swaps – 2016 39,894.0 3.57 Swaps – 2017 21,900.0 3.24 Natural Gas Liquids (MBbls): Swap – 2016 3.7 9.14 As of December 31, 2015, we had also entered into interest rate swaps with the following terms: Period Covered Notional Amount Floating Rate Fixed Rate January 2017 – December 2017 $ 100,000 1 Month LIBOR 1.039% January 2018 – September 2020 100,000 1 Month LIBOR 1.795% The following table sets forth the fair values and classification of our outstanding derivatives: Gross Net Amounts Amounts of Assets Gross Offset Presented Amounts in the in the of Consolidated Consolidated Recognized Balance Balance Assets Sheets Sheets Derivatives: As of December 31, 2015: Derivative asset $ 60,662 $ - $ 60,662 Long–term derivative asset 10,741 - 10,741 Total $ 71,403 $ - $ 71,403 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 Gross Net Amounts Amounts of Liabilities Gross Offset Presented Amounts in the in the of Consolidated Consolidated Recognized Balance Balance Liabilities Sheets Sheets Derivatives: As of December 31, 2014: Derivative liability $ 1,710 $ (1,710) $ - Long–term derivative liability - - - Total $ 1,710 $ (1,710) $ - 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, w e 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, 2015 and 2014, 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, 2015
Fair Value Measurements [Abstract]
Fair Value Measurements	NOTE 7. FAIR VALUE MEASUREMENTS The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value. 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 Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs Fair Value (Level 1) (Level 2) (Level 3) As of December 31, 2015: Assets: Oil, natural gas and natural gas liquids derivatives $ 70,356 $ - $ 70,356 $ - Interest rate swaps 1,047 - 1,047 - $ 71,403 $ - $ 71,403 $ - As of December 31, 2014: Assets – Oil and natural gas derivatives $ 135,401 $ - $ 135,401 $ - Liabilities – Interest rate swaps $ 1,710 $ - $ 1,710 $ - 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 2015. 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 Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs Total Fair Value (Level 1) (Level 2) (Level 3) Losses Year ending December 31: 2015: Long–lived assets held and used $ 52,406 $ - $ - $ 52,406 $ 86,892 Goodwill - - - - 65,924 $ 52,406 $ - $ - $ 52,406 $ 152,816 2014: 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: 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 Long–lived Assets Held and Used As a result of reductions in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids , we incurred impairment charges of $86.9 million, $103.1 million and $76.3 million in 2015, 2014 and 2013, respectively, to write down oil and natural gas properties to their fair value. These impairment charges were included in earnings in 2015, 2014 and 2013, respectively. 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, appropriate risk–adjusted discount rates and other relevant data. Long–lived Assets Held for Sale In 2014 and 2013, we incurred additional impairment charges of $0.2 million and $0.5 million, respectively, to write down assets held for sale to their fair value. These impairment charges were included in earnings for 2014 and 2013, respectively. 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. Goodwill In 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We have only one reporting unit, and we determined the fair value of the reporting unit using a combination of the market approach and the income approach. Under the market approach, the fair value was based on the quoted market price for our common units as of December 31, 2015 (our market capitalization), adjusted for a control premium. The determination of the control premium was based on our judgment as to what we believe would be standard in our industry. Under the income approach, t he fair value was based on the expected present value of the future net cash flows. Significant Level 3 assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk–adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $ 65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill. 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, 2015 and December 31, 2014, the estimated fair value of our senior notes due 2019 was $ 211.9 million and $ 427.5 million, respectively, which differs from the carrying value of $ 423.6 million and $ 496.3 million, respectively. T he 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, 2015
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	NOTE 8. ASSET RETIREMENT OBLIGATIONS The changes in the aggregate ARO are as follows: Balance as of December 31, 2013 $ 103,173 Liabilities incurred and assumed in acquisitions 753 Accretion expense 4,835 Revisions in estimated cash flows 432 Settlements and divestitures (3,420) Balance as of December 31, 2014 105,773 Liabilities incurred and assumed in acquisitions 70,005 Accretion expense 5,531 Revisions in estimated cash flows 1,344 Settlements and divestitures (5,720) Balance as of December 31, 2015 $ 176,933 As of December 31, 2015 and 2014, $2.9 million and $ 1.9 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our consolidated balance sheets.

Long-Term Debt, Net

Long-Term Debt, Net	12 Months Ended
	Dec. 31, 2015
Long-Term Debt, Net [Abstract]
Long-Term Debt, Net	NOTE 9. LONG–TERM DEBT , NET Long–term debt , net consisted of the following as of December 31: 2015 2014 Credit facility $ 265,000 $ 531,000 8.0% senior notes due 2019: Principal outstanding 426,022 500,000 Unamortized discount and debt issuance costs (1) (5,116) (7,652) Unaccreted premium (2) 2,708 4,001 423,614 496,349 Total $ 688,614 $ 1,027,349 _____________ (1) Imputed interest rate of 8.87% and 8.52% for 2015 and 2014, respectively. (2) Imputed interest rate of 7.35% and 7.62% for 2015 and 2014 , respectively . Credit Facility As of December 31, 2015, we have a $ 1.0 billion credit facility that expires in February 2020 . 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. As of December 31, 2015, we have a $0.4 million letter of credit outstanding. 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 3.0 to 1.0 . As of December 31, 2015, we were in compliance with these financial covenants . The facility does not require any repayments of amounts outstanding until it expires in February 2020. Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.73 % and 2.98 % at December 31, 2015 and 2014, 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, 2015, the borrowing base under the facility was $ 625.0 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. 8.0% Senior Notes due 2019 Our 8.0% senior unsecured notes due 2019 (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. In 2015, we redeemed $74.0 million of the Notes for $50.0 million, resulting in a gain on the early extinguishment of debt of $24.0 million. The remaining Notes are subject to redemption, at our option, 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 2016 102.00% 2017 and thereafter 100.00% 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies [Abstract]
Commitments and Contingencies	NOTE 10. 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, 2015 and 2014. 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, 201 5 , our future minimum transportation fees under this agreement are as follows for the years ended December 31: 2016 $ 619 2017 618 2018 619 2019 618 2020 619 Thereafter 1,031 $ 4,124

Owners' Equity

Owners' Equity	12 Months Ended
	Dec. 31, 2015
Owners' Equity [Abstract]
Owners' Equity	NOTE 11. OWNERS’ EQUITY Units Outstanding At December 31, 2015, owner’s equity consists of 48,871,399 common units outstanding (including 4,956,505 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 Offering 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. 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 gene ral 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 $0.7615 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, 2015 and 2014: Date Paid Period Covered Distribution per Unit Total Distribution February 13, 2015 October 1, 2014 – December 31, 2014 $ 0.500 $ 25,274 May 15, 2015 January 1, 2015 – March 31, 2015 0.500 25,221 August 14, 2015 April 1, 2015 – June 30, 2015 0.500 25,243 November 13, 2015 July 1, 2015 – September 30, 2015 0.500 25,241 $ 100,979 February 14, 2014 October 1, 2013 – December 31, 2013 $ 0.771 $ 38,696 May 15, 2014 January 1, 2014 – March 31, 2014 0.772 38,716 August 14, 2014 April 1, 2014 – June 30, 2014 0.773 38,760 November 14, 2014 July 1, 2014 – September 30, 2014 0.774 38,806 $ 154,978 On January 25, 2016 , the board of directors of EV Management declared a $ 0.075 per unit distribution for the fourth quarter of 2015 on all outstanding units. The distribution was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016 . The aggregate amount of the distribution was $ 3.9 million.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Income Taxes	NOTE 12. INCOME TAXES In December 2015 , we converted Belden from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion. As of December 31, 2015, Belden is no longer a tax paying entity. Income taxes were as follows for the year ended December 31, 2015: Current: Federal $ 11,207 State 235 11,442 Deferred: Federal (12,482) State (803) (13,285) $ (1,843) Of the $236.0 million of loss from continuing operations before income taxes, $45.7 million represents the loss that is subject to federal taxation. The effective tax rate on the loss subject to federal taxation differs from the U.S. statutory rate as follows for 2015: Income taxes at U.S. statutory income tax rate $ (15,986) Impairment of Belden goodwill 15,989 Belden deferred tax liability released at conversion (2,070) State income taxes, net of federal tax benefit 224 Income taxes $ (1,843)

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Discontinued Operations	NOTE 13. DISCONTINUED OPERATIONS Our midstream segment, which consisted of our investments in UEO and Cardinal, was engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. In June 2015, we sold our interest in UEO and received net proceeds of $572.2 million and recognized a gain of $246.7 million. In October 2014, we sold our interest in Cardinal and received net proceeds of $161.1 million and recognized a gain of $92.1 million. These gains are included in “Income from discontinued operations.” As a result of the reduction in the borrowing base under our facility upon the sale of our interest in UEO, we were required to repay $25.0 million of outstanding borrowings. Accordingly, $1.5 million of interest related to this $25.0 million and the write off of deferred financing costs related to the reduction in the borrowing base have been allocated to “Income from discontinued operations” in 2015. Summarized financial information for our midstream segment was as follows: 2014 (1) Current assets $ 98,061 Noncurrent assets 1,381,773 Total assets $ 1,479,834 Current liabilities $ 37,967 Owner’s equity 1,441,867 Total liabilities and owner’s equity $ 1,479,834 2015 (1) 2014 (2) 2013 (2) Revenues $ 93,726 $ 237,344 $ 56,888 Operating income 49,171 109,003 4,955 Net income 49,525 109,660 5,125 _____________ (1) Information is for UEO on a stand–alone basis through the date of divestiture. (2) Information is for UEO and Cardinal on a combined basis.

Earnings Per Limited Partner Un

Earnings Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Limited Partner Unit [Abstract]
Net Income (Loss) Per Limited Partner Unit	NOTE 14. EARNINGS PER LIMITED PARTNER UNIT The following sets forth the calculation of earnings per limited partner unit for the years ended December 31: 2015 2014 2013 (Loss) income from continuing operations $ (234,179) $ 22,245 $ (75,624) General partner's 2% interest in (loss) income from continuing operations 4,684 (445) 1,513 Earnings attributable to unvested phantom units (1,076) (1,723) (2,006) Limited partners' interest in (loss) income from continuing operations $ (230,571) $ 20,077 $ (76,117) Earnings per limited partner unit (basic and diluted) $ (4.72) $ 0.41 $ (1.75) Income (loss) from discontinued operations $ 255,512 $ 107,475 $ (603) General partner's 2% interest in income (loss) from discontinued operations (5,110) (2,150) 12 Earnings attributable to unvested phantom units - - - Limited partners' interest in income (loss) from discontinued operations $ 250,402 $ 105,325 $ (591) Earnings per limited partner unit (basic and diluted) $ 5.13 $ 2.17 $ (0.01) Net income (loss) $ 21,333 $ 129,720 $ (76,227) General partner's 2% interest in net income (loss) (426) (2,595) 1,525 Earnings attributable to unvested phantom units (1,076) (1,723) (2,006) Limited partners' interest in net income (loss) $ 19,831 $ 125,402 $ (76,708) Earnings per limited partner unit (basic and diluted) $ 0.41 $ 2.58 $ (1.76) Weighted average limited partner units outstanding (basic and diluted) 48,853 48,563 43,691 As of December 31, 2015, there are no unearned performance units outstanding. As of both December 31, 2014 and 2013, 0.2 million unearned performance units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti-dilutive.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 15. RELATED PARTY TRANSACTIONS Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $ 14.2 million, $12.1 million and $10.0 million in 201 5 , 201 4 and 201 3 , 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. W e 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 2015, 2014 and 2013, we reimbursed EnerVest approximately $ 17.2 million, $17.0 million and $17.1 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 October 2015, we acquired oil and natural gas properties in the Appalachian Basin, the San Juan Basin, Michigan and the Austin Chalk from certain institutional partnerships managed by EverVest for a combined cash consideration of $259.0 million (see Note 4). In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from certain acres in Ohio (the "Underlying Properties"), which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership. EnerVest is the general partner of this partnership. The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties. We own a 48% limited partner interest in the partnership and account for our investment using the equity method of accounting. We recognized $0.2 million, $0.4 million and $0.2 million of income in 2015, 2014 and 2013, respectively, and we received $0.2 million, $0.3 million and $0.2 million of distributions in 2015, 2014 and 2013, respectively.

Quarterly Data

Quarterly Data	12 Months Ended
	Dec. 31, 2015
Quarterly Data [Abstract]
Quarterly Data	NOTE 17. QUARTERLY DATA (UNAUDITED) First Second Third Fourth Quarter Quarter Quarter Quarter 2015 Revenues (1) $ 47,242 $ 44,456 $ 38,321 $ 47,952 Gross profit (2) 21,396 18,549 13,945 15,683 Net (loss) income (3) (61,667) 164,102 (9,838) (71,264) Net (loss) income per limited partner unit: Basic $ (1.25) $ 3.25 $ (0.20) $ (1.43) Diluted $ (1.25) $ 3.25 $ (0.20) $ (1.43) 2014 Revenues $ 95,339 $ 89,360 $ 84,531 $ 70,175 Gross profit (2) 65,451 59,433 54,105 39,126 Net (loss) income (3) (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 _____________ (1) Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4). (2) Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes. (3) Includes gain on sale of our investment in UEO of $2 46.7 million in the second quarter of 2015 and gain on sale of our investment in Cardinal of $92.1 million in the fourth quarter of 2014.

Supplementary Information on Oi

Supplementary Information on Oil and Natural Gas Activities	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 Proved oil and natural gas properties $ 2,694,354 $ 2,371,866 Unproved oil and natural gas properties 67,600 117,738 2,761,954 2,489,604 Accumulated depreciation, depletion and amortization (971,499) (778,679) Net capitalized costs $ 1,790,455 $ 1,710,925 Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31: 2015 2014 2013 Acquisition of oil and natural gas properties: Proved $ 236,356 $ - $ 59,602 Unproved 1,020 - 6,018 Exploration costs 2,193 2,585 1,764 Development costs 55,109 103,840 108,486 Total $ 294,678 $ 106,425 $ 175,870

Estimated Proved Oil, Natural G

Estimated Proved Oil, Natural Gas and Natural Liquids Reserves	12 Months Ended
	Dec. 31, 2015
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, 2015 have been prepared by Cawley, Gillespie & Associates, Inc. and Wright & Company, Inc., independent petroleum consultants. The estimates of our proved reserves as of December 31, 2014 and 2013 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 Oil Natural Gas Liquids (MBbls) (1) (Mmcf) (2) (MBbls) (1) Mmcfe (3) Proved developed and undeveloped reserves: 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 (4) 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 (5) (1,851) (138,666) (16,180) (246,856) Purchases of minerals in place 21 1,515 222 2,974 Extensions and discoveries (6) 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 Revisions of previous estimates (7) (3,319) (194,442) (9,028) (268,522) Purchases of minerals in place 11,852 214,578 7,468 330,504 Extensions and discoveries (8) 2,636 60,197 4,106 100,647 Production (1,041) (43,592) (2,326) (63,792) Sales of minerals in place (41) (1,918) (69) (2,580) As of December 31, 2015 21,995 747,015 36,294 1,096,753 Proved developed reserves: December 31, 2012 11,153 473,223 24,832 689,133 December 31, 2013 10,443 578,274 29,056 815,268 December 31, 2014 9,783 599,664 30,766 842,956 December 31, 2015 13,919 644,984 30,091 909,047 Proved undeveloped reserves: December 31, 2012 2,355 136,323 10,847 215,536 December 31, 2013 2,641 241,406 19,846 376,326 December 31, 2014 2,125 112,528 5,377 157,540 December 31, 2015 8,076 102,031 6,203 187,706 _____________ (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) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 177.1 Bcfe). (5) 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. (6) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 78.2 Bcfe ) and the Appalachian Basin ( 33.0 Bcfe). (7) Revisions were primarily attributable to the Barnett Shale (120.7 Bcfe) and the Appalachian Basin (76.9 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2015 reserve estimates from prices used in our December 31, 2014 reserve estimates. (8) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (72.6 Bcfe) and the Appalachian Basin (16.9 Bcfe).

Standardized Measure of Discont

Standardized Measure of Discontinued Future Net Cash Flows Relating to Proved Oil, Natural Gas and Natural Gas Liquids Reserves	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 Future cash inflows $ 3,285,271 $ 4,639,547 $ 4,998,790 Future production and development costs (2,029,001) (2,123,559) (2,509,542) Future income tax expenses (7,769) (18,266) (22,091) Future net cash flows 1,248,501 2,497,722 2,467,157 10% annual discount for estimated timing of cash flows (712,051) (1,404,419) (1,427,372) Standardized measure of discounted future net cash flows $ 536,450 $ 1,093,303 $ 1,039,785 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, 2015, 2014 and 2013 were $50.28 per Bbl of oil, $2.587 per MMBtu of natural gas; $ 94.99 per Bbl of oil, $4.35 per MMBtu of natural gas; and $ 96.78 per Bbl of oil, $ 3.666 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: 2015 2014 2013 Standardized measure at beginning of period $ 1,093,303 $ 1,039,785 $ 866,932 Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs (68,479) (216,972) (194,942) Net changes in prices and production costs (682,598) 131,899 (1,264) Extensions, discoveries and improved recovery, less related costs 26,082 113,127 113,714 Development costs incurred during the period 21,441 23,737 17,762 Revisions and other (205,821) (69,407) 53,427 Accretion of 10% timing discount 110,120 104,941 87,433 Changes in income taxes 4,362 1,725 (2,218) Changes in estimated future development costs 19,925 (2,980) 1,692 Changes in timing and other (31,118) (28,853) 55,966 Purchase of minerals in place 250,646 4,376 41,810 Sales of minerals in place (1,413) (8,075) (527) Standardized measure of discounted future net cash flows $ 536,450 $ 1,093,303 $ 1,039,785

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
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 units, 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, 2015 and 2014, 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 $ 67.6 million and $ 117.7 million as of December 31, 2015 and December 31, 2014, 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 2015, 2014 and 2013, we recorded dry hole and exploration costs of $ 3.7 million, $ 6.7 million and $ 2.4 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 Oil and Natural Gas Properties 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 2015, 2014 and 2013, we recorded impairment charges of $86.9 million, $ 103.3 million and $ 76.9 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 7). Since December 31, 2015, commodity prices have continued to deteriorate. If commodity prices do not improve before March 31, 2016, we anticipate additional impairments of our oil and natural gas properties. Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized. For 2015, 2014 and 2013, we recorded impairment charges of $49.8 million, $ 10.7 million and $ 8.5 million, respectively, related to unproved oil and natural gas properties where we had a change in development plans for the acreage.
Goodwill	Goodwill We recorded $65.9 million of goodwill in conjunction with our October 2015 acquisitions (see Note 4). Goodwill was calculated as the excess of the purchase price over the estimated fair values of the assets acquired net of the liabilities assumed in the acquisitions. The goodwill was not amortized, but was evaluated for impairment as the declining oil and natural price environment indicated the carrying value of goodwill may not be recoverable (see Note 7). The changes in the carrying amount of goodwill are as follows: Balance as of December 31, 2014 $ - Goodwill acquired during the year 65,924 Impairment losses (65,924) Balance as of December 31, 2015 $ -
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.
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, 2015 or 2014. We own and operate a network of natural gas gathering systems in the Appalachian Basin and 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. In October 2015, we acquired Belden & Blake Corporation (“Belden”), a taxable entity (see Note 4). We used the asset and liability method of accounting for income taxes. Under this method, deferred taxes were provided for temporary differences as of the date of acquisition between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In December 2015, Belden was converted from a corporation into a single member limited liability company (see Note 12).
Net Income Per Limited Partner Unit	Earnings per Limited Partner Unit We use the two–class method to compute earnings per limited partner unit. The two-class method is an earnings allocation formula that determines earnings per unit for our common units and participating securities as if all earnings for the period had been distributed. As our unvested phantom units and our earned but unvested performance units participate in dividends on an equal basis with our common units, they are considered to be participating securities. Earnings used in the determination of earnings per limited partner unit for the current reporting period are reduced by the amount of earnings allocated to the general partner and available cash that will be distributed to the limited partners and the participating securities. The undistributed earnings, if any, are then allocated to the limited partners and the participating securities in accordance with the terms of the partnership agreement. Basic and diluted earnings per limited partner unit are then calculated by dividing earnings, after deducting the amount allocated to the general partner and the earnings attributable to the participating securities, 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, 2015, 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 2015, two customers accounted for 17.1% and 10.8% , respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2014 and 2013, 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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09, Revenue from Contracts with Customers. This ASU superseded 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. In August 2015, the FASB issued ASU 2015–14 that deferred the adoption of ASU 2014–09 for one year. The provisions of ASU 2014–09 are now applicable to annual reporting periods beginning after December 15, 2017 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 April 2015, the FASB issued ASU No. 2015–03, Interest – Imputation of Interest . This ASU changes the presentation of debt issuance costs in financial statements. Under ASU 2015–03, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. As the guidance in this ASU did not address presentation or subsequent measurement of debt issuance costs related to line–of–credit arrangements, the FASB issued ASU 2015–15, Interest – Imputation of Interest, in August 2015 to clarify that these presentation requirements did not apply to line–of–credit arrangements. We adopted ASU 2015–03 and ASU 2015–15 on December 31, 2015, which required that we apply the guidance on a retrospective basis, wherein our consolidated balance sheets for all periods presented were adjusted to reflect the effects of applying the guidance. Accordingly, as of December 31, 2014, we reclassified $ 3.0 million of debt issuance costs previously reported in “Other assets” to “Long–term debt , net” on our consolidated balance sheet. In addition, as of December 31, 2015, we presented $ 2.0 million of debt issuance costs as a reduction of long–term debt on our consolidated balance sheet. In April 2015, the FASB issued ASU No. 2015–06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions . ASU 2015–06 specifies that for purposes of calculating historical earnings per unit under the two class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In addition, qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two class method are also required. The provisions of ASU 2015–06 are applicable to annual reporting periods beginning after December 15, 2015 and interim periods within those annual periods. We will adopt this ASU should we enter into a dropdown transaction. In September 2015, the FASB issued ASU 2015–16, Simplifying the Accounting for Measurement Period Adjustments. To simplify the accounting for adjustments made to provisional amounts, ASU 2015–16 requires that the acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amount is determined. The provisions of ASU 2015–16 are effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. We will adopt this ASU should we report provisional amounts for items in a business combination. No other new accounting pronouncements issued or effective during the year ended December 31, 2015 have had or are expected to have a material impact on our consolidated financial statements.
Subsequent Events	Subsequent Events We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Schedule of Goodwill	The changes in the carrying amount of goodwill are as follows: Balance as of December 31, 2014 $ - Goodwill acquired during the year 65,924 Impairment losses (65,924) Balance as of December 31, 2015 $ -

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
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: Number Weighted Average of Grant Date Phantom Units Fair Value Nonvested phantom units as of December 31, 2014 988,325 $ 37.00 Granted 1,088,303 2.61 Vested (338,661) 44.93 Forfeited (48,719) 32.25 Nonvested phantom units as of December 31, 2015 1,689,248 $ 13.39
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: 2015 2014 2013 Weighted average fair value of phantom units $ 2.61 $ 22.77 $ 31.92 Expected volatility 62.33% 34.52% 30.78% Risk–free interest rate 1.13% 0.87% 0.68% Dividend yield 0.0% 0.0% 0.0% Expected life (years) 4.1 4.0 4.0
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: Number of Weighted Average Performance Grant Date Units Fair Value Nonvested performance units as of December 31, 2014 193,500 $ 64.07 Vested (21,500) 73.78 Forfeited (172,000) 59.21 Nonvested performance units as of December 31, 2015 - $ -

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Barnett Shale [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
Appalachin Basin, San Juan Basin, Michigan and Austin Chalk Properties [Member]
Business Acquisition [Line Items]
Pro Forma Revenues, Net Income And Net Income Per Limited Partner Unit	2015 2014 Revenues: Historical $ 177,971 $ 339,405 Belden 24,292 65,453 Austin Chalk 9,235 24,074 Appalachian and San Juan Basins 23,738 59,490 Pro forma revenues $ 235,236 $ 488,422 Net income (loss): Historical $ 21,333 $ 129,720 Belden (76,910) (1,794) Austin Chalk 1,217 11,395 Appalachian and San Juan Basins 414 19,380 Pro forma net income $ (53,946) $ 158,701
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 these acquisitions are as follows: Appalachian and San Juan Belden Austin Chalk Basins Total Cash $ 8,665 $ - $ - $ 8,665 Accounts receivable 7,901 - - 7,901 Derivative asset 2,711 - - 2,711 Other current assets 1,053 318 1,318 2,689 Proved oil and natural gas properties 105,626 28,513 136,176 270,315 Unproved oil and natural gas properties - 1,020 - 1,020 Goodwill 45,681 - 20,243 65,924 Long-term derivative assets 128 - - 128 Other assets 1,150 - - 1,150 Accounts payable and accrued liabilities (11,308) (256) (5,456) (17,020) Income taxes (974) - - (974) Deferred taxes (13,409) - - (13,409) Asset retirement obligations (35,551) (3,698) (30,260) (69,509) Other long-term liabilities (569) - - (569) $ 111,104 $ 25,897 $ 122,021 $ 259,022

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2015
Risk Management [Abstract]
Schedule of Commodity Contracts	As of December 31, 2015, we had entered into oil, natural gas and natural gas liquids derivatives with the following terms: Weighted Average Hedged Fixed Period Covered Volume Price Oil (MBbls): Swaps – 2016 366.0 $ 90.14 Natural Gas (MmmBtus): Swaps – 2016 39,894.0 3.57 Swaps – 2017 21,900.0 3.24 Natural Gas Liquids (MBbls): Swap – 2016 3.7 9.14
Interest Rate Swaps	As of December 31, 2015, we had also entered into interest rate swaps with the following terms: Period Covered Notional Amount Floating Rate Fixed Rate January 2017 – December 2017 $ 100,000 1 Month LIBOR 1.039% January 2018 – September 2020 100,000 1 Month LIBOR 1.795%
Fair Value of Derivatives	The following table sets forth the fair values and classification of our outstanding derivatives: Gross Net Amounts Amounts of Assets Gross Offset Presented Amounts in the in the of Consolidated Consolidated Recognized Balance Balance Assets Sheets Sheets Derivatives: As of December 31, 2015: Derivative asset $ 60,662 $ - $ 60,662 Long–term derivative asset 10,741 - 10,741 Total $ 71,403 $ - $ 71,403 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 Gross Net Amounts Amounts of Liabilities Gross Offset Presented Amounts in the in the of Consolidated Consolidated Recognized Balance Balance Liabilities Sheets Sheets Derivatives: As of December 31, 2014: Derivative liability $ 1,710 $ (1,710) $ - Long–term derivative liability - - - Total $ 1,710 $ (1,710) $ -

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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 Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs Fair Value (Level 1) (Level 2) (Level 3) As of December 31, 2015: Assets: Oil, natural gas and natural gas liquids derivatives $ 70,356 $ - $ 70,356 $ - Interest rate swaps 1,047 - 1,047 - $ 71,403 $ - $ 71,403 $ - As of December 31, 2014: Assets – Oil and natural gas derivatives $ 135,401 $ - $ 135,401 $ - Liabilities – Interest rate swaps $ 1,710 $ - $ 1,710 $ -
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 Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs Total Fair Value (Level 1) (Level 2) (Level 3) Losses Year ending December 31: 2015: Long–lived assets held and used $ 52,406 $ - $ - $ 52,406 $ 86,892 Goodwill - - - - 65,924 $ 52,406 $ - $ - $ 52,406 $ 152,816 2014: 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: 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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations [Abstract]
Changes in Aggregate Asset Retirement Obligations	The changes in the aggregate ARO are as follows: Balance as of December 31, 2013 $ 103,173 Liabilities incurred and assumed in acquisitions 753 Accretion expense 4,835 Revisions in estimated cash flows 432 Settlements and divestitures (3,420) Balance as of December 31, 2014 105,773 Liabilities incurred and assumed in acquisitions 70,005 Accretion expense 5,531 Revisions in estimated cash flows 1,344 Settlements and divestitures (5,720) Balance as of December 31, 2015 $ 176,933

Long-Term Debt, Net (Tables)

Long-Term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2015
Long-Term Debt, Net [Abstract]
Long Term Debt	Long–term debt , net consisted of the following as of December 31: 2015 2014 Credit facility $ 265,000 $ 531,000 8.0% senior notes due 2019: Principal outstanding 426,022 500,000 Unamortized discount and debt issuance costs (1) (5,116) (7,652) Unaccreted premium (2) 2,708 4,001 423,614 496,349 Total $ 688,614 $ 1,027,349 _____________ (1) Imputed interest rate of 8.87% and 8.52% for 2015 and 2014, respectively. (2) Imputed interest rate of 7.35% and 7.62% for 2015 and 2014 , respectively .
Redemption Prices on Applicable Redemption Dates	The remaining Notes are subject to redemption, at our option, 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 2016 102.00% 2017 and thereafter 100.00%

Owners' Equity (Tables)

Owners' Equity (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014: Date Paid Period Covered Distribution per Unit Total Distribution February 13, 2015 October 1, 2014 – December 31, 2014 $ 0.500 $ 25,274 May 15, 2015 January 1, 2015 – March 31, 2015 0.500 25,221 August 14, 2015 April 1, 2015 – June 30, 2015 0.500 25,243 November 13, 2015 July 1, 2015 – September 30, 2015 0.500 25,241 $ 100,979 February 14, 2014 October 1, 2013 – December 31, 2013 $ 0.771 $ 38,696 May 15, 2014 January 1, 2014 – March 31, 2014 0.772 38,716 August 14, 2014 April 1, 2014 – June 30, 2014 0.773 38,760 November 14, 2014 July 1, 2014 – September 30, 2014 0.774 38,806 $ 154,978
Subsequent to IDR reset election
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 gene ral 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 $0.7615 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%

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income taxes were as follows for the year ended December 31, 2015: Current: Federal $ 11,207 State 235 11,442 Deferred: Federal (12,482) State (803) (13,285) $ (1,843)
Schedule of Effective Income Tax Rate Reconciliation	The effective tax rate on the loss subject to federal taxation differs from the U.S. statutory rate as follows for 2015: Income taxes at U.S. statutory income tax rate $ (15,986) Impairment of Belden goodwill 15,989 Belden deferred tax liability released at conversion (2,070) State income taxes, net of federal tax benefit 224 Income taxes $ (1,843)

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Discontinued Operation Financial Information	Summarized financial information for our midstream segment was as follows: 2014 (1) Current assets $ 98,061 Noncurrent assets 1,381,773 Total assets $ 1,479,834 Current liabilities $ 37,967 Owner’s equity 1,441,867 Total liabilities and owner’s equity $ 1,479,834 2015 (1) 2014 (2) 2013 (2) Revenues $ 93,726 $ 237,344 $ 56,888 Operating income 49,171 109,003 4,955 Net income 49,525 109,660 5,125 _____________ (1) Information is for UEO on a stand–alone basis through the date of divestiture. (2) Information is for UEO and Cardinal on a combined basis.

Earnings Per Limited Partner 38

Earnings Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Limited Partner Unit [Abstract]
Calculation of Net Income (Loss) Per Limited Partner Unit	The following sets forth the calculation of earnings per limited partner unit for the years ended December 31: 2015 2014 2013 (Loss) income from continuing operations $ (234,179) $ 22,245 $ (75,624) General partner's 2% interest in (loss) income from continuing operations 4,684 (445) 1,513 Earnings attributable to unvested phantom units (1,076) (1,723) (2,006) Limited partners' interest in (loss) income from continuing operations $ (230,571) $ 20,077 $ (76,117) Earnings per limited partner unit (basic and diluted) $ (4.72) $ 0.41 $ (1.75) Income (loss) from discontinued operations $ 255,512 $ 107,475 $ (603) General partner's 2% interest in income (loss) from discontinued operations (5,110) (2,150) 12 Earnings attributable to unvested phantom units - - - Limited partners' interest in income (loss) from discontinued operations $ 250,402 $ 105,325 $ (591) Earnings per limited partner unit (basic and diluted) $ 5.13 $ 2.17 $ (0.01) Net income (loss) $ 21,333 $ 129,720 $ (76,227) General partner's 2% interest in net income (loss) (426) (2,595) 1,525 Earnings attributable to unvested phantom units (1,076) (1,723) (2,006) Limited partners' interest in net income (loss) $ 19,831 $ 125,402 $ (76,708) Earnings per limited partner unit (basic and diluted) $ 0.41 $ 2.58 $ (1.76) Weighted average limited partner units outstanding (basic and diluted) 48,853 48,563 43,691 As of December 31, 2015, there are no unearned performance units outstanding. As of both December 31, 2014 and 2013, 0.2 million unearned performance units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti-dilutive.

Other Supplemental Information

Other Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 Supplemental cash flows information: Cash paid for interest, net of capitalized interest of $5,741 and $7,276 $ 48,344 $ 49,444 $ 45,355 at December 31, 2014 and 2013, respectively Cash (refunded) paid for income taxes (115) 155 325 Non–cash transactions: Costs for additions to oil and natural gas properties in accounts payable and accrued liabilities 5,212 18,028 19,450
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued liabilities consisted of the following as of December 31: 2015 2014 Costs for additions to oil and natural gas properties $ 5,212 $ 18,028 Lease operating expenses 10,576 9,701 Interest 7,298 8,649 Production and ad valorem taxes 6,763 5,683 VPP 3,984 - General and administrative expenses 2,864 2,317 Current portion of ARO 2,930 1,941 Derivative settlements - 280 Other 3,508 1,279 Total $ 43,135 $ 47,878

Quarterly Data (Tables)

Quarterly Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Data [Abstract]
Schedule of Quarterly Data	First Second Third Fourth Quarter Quarter Quarter Quarter 2015 Revenues (1) $ 47,242 $ 44,456 $ 38,321 $ 47,952 Gross profit (2) 21,396 18,549 13,945 15,683 Net (loss) income (3) (61,667) 164,102 (9,838) (71,264) Net (loss) income per limited partner unit: Basic $ (1.25) $ 3.25 $ (0.20) $ (1.43) Diluted $ (1.25) $ 3.25 $ (0.20) $ (1.43) 2014 Revenues $ 95,339 $ 89,360 $ 84,531 $ 70,175 Gross profit (2) 65,451 59,433 54,105 39,126 Net (loss) income (3) (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 _____________ (1) Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4). (2) Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes. (3) Includes gain on sale of our investment in UEO of $2 46.7 million in the second quarter of 2015 and gain on sale of our investment in Cardinal of $92.1 million in the fourth quarter of 2014.

Supplementary Information On 41

Supplementary Information On Oil And Natural Gas Activities (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 Proved oil and natural gas properties $ 2,694,354 $ 2,371,866 Unproved oil and natural gas properties 67,600 117,738 2,761,954 2,489,604 Accumulated depreciation, depletion and amortization (971,499) (778,679) Net capitalized costs $ 1,790,455 $ 1,710,925
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: 2015 2014 2013 Acquisition of oil and natural gas properties: Proved $ 236,356 $ - $ 59,602 Unproved 1,020 - 6,018 Exploration costs 2,193 2,585 1,764 Development costs 55,109 103,840 108,486 Total $ 294,678 $ 106,425 $ 175,870

Estimated Proved Oil, Natural42

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves (Tables)	12 Months Ended
	Dec. 31, 2015
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 Oil Natural Gas Liquids (MBbls) (1) (Mmcf) (2) (MBbls) (1) Mmcfe (3) Proved developed and undeveloped reserves: 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 (4) 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 (5) (1,851) (138,666) (16,180) (246,856) Purchases of minerals in place 21 1,515 222 2,974 Extensions and discoveries (6) 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 Revisions of previous estimates (7) (3,319) (194,442) (9,028) (268,522) Purchases of minerals in place 11,852 214,578 7,468 330,504 Extensions and discoveries (8) 2,636 60,197 4,106 100,647 Production (1,041) (43,592) (2,326) (63,792) Sales of minerals in place (41) (1,918) (69) (2,580) As of December 31, 2015 21,995 747,015 36,294 1,096,753 Proved developed reserves: December 31, 2012 11,153 473,223 24,832 689,133 December 31, 2013 10,443 578,274 29,056 815,268 December 31, 2014 9,783 599,664 30,766 842,956 December 31, 2015 13,919 644,984 30,091 909,047 Proved undeveloped reserves: December 31, 2012 2,355 136,323 10,847 215,536 December 31, 2013 2,641 241,406 19,846 376,326 December 31, 2014 2,125 112,528 5,377 157,540 December 31, 2015 8,076 102,031 6,203 187,706 _____________ (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) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 177.1 Bcfe). (5) 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. (6) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 78.2 Bcfe ) and the Appalachian Basin ( 33.0 Bcfe). (7) Revisions were primarily attributable to the Barnett Shale (120.7 Bcfe) and the Appalachian Basin (76.9 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2015 reserve estimates from prices used in our December 31, 2014 reserve estimates. (8) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (72.6 Bcfe) and the Appalachian Basin (16.9 Bcfe).

Standardized Measure Of Disco43

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, 2015
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: 2015 2014 2013 Future cash inflows $ 3,285,271 $ 4,639,547 $ 4,998,790 Future production and development costs (2,029,001) (2,123,559) (2,509,542) Future income tax expenses (7,769) (18,266) (22,091) Future net cash flows 1,248,501 2,497,722 2,467,157 10% annual discount for estimated timing of cash flows (712,051) (1,404,419) (1,427,372) Standardized measure of discounted future net cash flows $ 536,450 $ 1,093,303 $ 1,039,785
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: 2015 2014 2013 Standardized measure at beginning of period $ 1,093,303 $ 1,039,785 $ 866,932 Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs (68,479) (216,972) (194,942) Net changes in prices and production costs (682,598) 131,899 (1,264) Extensions, discoveries and improved recovery, less related costs 26,082 113,127 113,714 Development costs incurred during the period 21,441 23,737 17,762 Revisions and other (205,821) (69,407) 53,427 Accretion of 10% timing discount 110,120 104,941 87,433 Changes in income taxes 4,362 1,725 (2,218) Changes in estimated future development costs 19,925 (2,980) 1,692 Changes in timing and other (31,118) (28,853) 55,966 Purchase of minerals in place 250,646 4,376 41,810 Sales of minerals in place (1,413) (8,075) (527) Standardized measure of discounted future net cash flows $ 536,450 $ 1,093,303 $ 1,039,785

Organization and Nature of Bu44

Organization and Nature of Business (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
General partner interest in the Partnership, percentage	2.00%
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%	2.00%	2.00%

Summary of Significant Accoun45

Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)customer	Dec. 31, 2013USD ($)customer	Oct. 31, 2015USD ($)
Significant Accounting Policies [Line Items]
Capitalized costs associated with unproved properties	$ 67,600	$ 117,700
Dry hole and exploration costs	3,695	6,726	$ 2,380
Impairment of oil and natural gas properties	136,667	113,968	85,341
Senior secured credit facility, maximum borrowing capacity	1,000,000
Goodwill				$ 65,924
Accounting Standards Update 201503 [Member] | Restatement Adjustment [Member]
Significant Accounting Policies [Line Items]
Decrease to other assets		3,000
Increase to long term debt net		3,000
Decrease to long term debt net	2,000
Proved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	86,900	103,300	76,900
Unproved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	$ 49,800	$ 10,700	$ 8,500
Customer Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration risk, number of clients | customer		0	0
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Significant Accounting Policies [Line Items]
Concentration risk, number of clients | customer	2
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | Major Customer One [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	17.10%
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | Major Customer Two [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	10.80%
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

Summary of Significant Accoun46

Summary of Significant Accounting Policies (Schedule of Goodwill) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Summary Of Significant Accounting Policies [Abstract]
Goodwill acquired during the year	$ 65,924
Impairment losses	$ (65,924)

Equity-Based Compensation (Narr

Equity-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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		Sep. 20, 2016
Vested		338,661
Performance units issued to employees and executive officers		1,088,303
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units vesting period		4 years
Total fair value units vested				$ 2.4
Compensation cost related to phantom or performance units recognized				0.2
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		$ 15.2	$ 11.9	8.5
Compensation cost related to phantom or performance units recognized		11.8	$ 13.9	$ 11.9
Unrecognized compensation cost related to unvested phantom units		$ 14.7
Unrecognized compensation costs, weighted average period of recognition		2 years 6 months
Years used to calculate estimated volatility		2 years	2 years	2 years
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units issued to employees and executive officers	300,000
Percentage of performance units vested over the vesting period	25.00%
Number of performance units estimated using the Black-Scholes option pricing model	100,000
Total fair value units vested		$ 1.6	$ 1.4	$ 1.6
Compensation cost related to phantom or performance units recognized		$ 0.2	$ 5.4	$ 5.4

Equity-Based Compensation (Acti

Equity-Based Compensation (Activity Related To Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of Units
Nonvested units as of December 31, 2014	988,325
Granted	1,088,303
Vested	(338,661)
Forfeited	(48,719)
Nonvested units as of December 31, 2015	1,689,248	988,325
Weighted Average Grant Date Fair Value per Phantom Unit
Nonvested units as of December 31, 2014	$ 37
Granted	2.61
Vested	44.93
Forfeited	32.25
Nonvested units as of December 31, 2015	13.39	$ 37
Equity Awards [Member]
Weighted Average Grant Date Fair Value per Phantom Unit
Granted	$ 2.61	$ 22.77	$ 31.92
Performance Units [Member]
Number of Units
Nonvested units as of December 31, 2014	193,500
Vested	(21,500)
Forfeited	(172,000)
Nonvested units as of December 31, 2015		193,500
Weighted Average Grant Date Fair Value per Phantom Unit
Nonvested units as of December 31, 2014	$ 64.07
Vested	73.78
Forfeited	$ 59.21
Nonvested units as of December 31, 2015		$ 64.07

Equity-Based Compensation (Assu

Equity-Based Compensation (Assumptions Used To Estimate Weighted Average Fair Value) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Weighted average fair value of phantom units	$ 2.61
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	$ 2.61	$ 22.77	$ 31.92
Expected volatility	62.33%	34.52%	30.78%
Risk-free interest rate	1.13%	0.87%	0.68%
Dividend yield	0.00%	0.00%	0.00%
Expected life (years)	4 years 1 month 6 days	4 years	4 years

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2013USD ($)	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 31, 2015USD ($)MMcf	Nov. 30, 2013USD ($)
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price						$ 259,022
Oil, natural gas and natural gas liquids revenues			$ 175,088	$ 334,729	$ 310,883
Volume obligation to deliver, billion cubic feet (Bcf) of natural gas | MMcf						2,400
Volume obligation to deliver, remaining, (Bcf) of natrual gas | MMcf		1,900	1,900
Liability related to volumetric production payment (VPP)		$ 3,984	$ 3,984
Goodwill						$ 65,924
Business acquisition, goodwill, expected tax deductible amount						20,200
Accretion expense			$ 100
Barnett Shale [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired interest, percentage							31.00%
Oil and natural gas properties acquired, purchase price							$ 65,974
Oil, natural gas and natural gas liquids revenues					$ 1,400
Utica Shale [Member]
Business Acquisition [Line Items]
Amount received in relation to final purchase price settlement	$ 8,000
Belden [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price						111,104
Oil, natural gas and natural gas liquids revenues		5,600
Goodwill						45,681
Austin Chalk [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price						25,897
Oil, natural gas and natural gas liquids revenues		4,900
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price						122,021
Oil, natural gas and natural gas liquids revenues		$ 4,500
Goodwill						$ 20,243

Acquisitions (Pro Forma Revenue

Acquisitions (Pro Forma Revenues, Net Income and Net Income Per Limited Partner Unit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Appalachin Basin, San Juan Basin, Michigan and Austin Chalk Properties [Member]
Business Acquisition [Line Items]
Revenues	$ 235,236	$ 488,422
Net income	(53,946)	158,701
Historical [Member]
Business Acquisition [Line Items]
Revenues	177,971	339,405
Net income	21,333	129,720
Belden [Member]
Business Acquisition [Line Items]
Revenues	24,292	65,453
Net income	(76,910)	(1,794)
Austin Chalk [Member]
Business Acquisition [Line Items]
Revenues	9,235	24,074
Net income	1,217	11,395
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Revenues	23,738	59,490
Net income	$ 414	$ 19,380

Acquisitions (Recognized Fair V

Acquisitions (Recognized Fair Values of Identifiable Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Thousands	Oct. 31, 2015	Nov. 30, 2013
Business Acquisition [Line Items]
Cash	$ 8,665
Accounts receivable	7,901
Derivative asset	2,711
Other current assets	2,689
Proved oil and natural gas properties	270,315
Unproved oil and natural gas properties	1,020
Goodwill	65,924
Long-term derivative assets	128
Other assets	1,150
Accounts payable and accrued liabilities	(17,020)
Income taxes	(974)
Deferred taxes	(13,409)
Asset retirement obligations	(69,509)
Other long-term liabilities	(569)
Business acquisition, assets acquired (liabilities assumed), net	259,022
Barnett Shale [Member]
Business Acquisition [Line Items]
Accounts receivable (accrued liability)		$ (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 (accrued receivable and accrued asset)		(18)
Asset retirement obligations		(976)
Business acquisition, assets acquired (liabilities assumed), net		$ 65,974
Belden [Member]
Business Acquisition [Line Items]
Cash	8,665
Accounts receivable	7,901
Derivative asset	2,711
Other current assets	1,053
Proved oil and natural gas properties	105,626
Goodwill	45,681
Long-term derivative assets	128
Other assets	1,150
Accounts payable and accrued liabilities	(11,308)
Income taxes	(974)
Deferred taxes	(13,409)
Asset retirement obligations	(35,551)
Other long-term liabilities	(569)
Business acquisition, assets acquired (liabilities assumed), net	111,104
Austin Chalk [Member]
Business Acquisition [Line Items]
Other current assets	318
Proved oil and natural gas properties	28,513
Unproved oil and natural gas properties	1,020
Accounts payable and accrued liabilities	(256)
Asset retirement obligations	(3,698)
Business acquisition, assets acquired (liabilities assumed), net	25,897
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Other current assets	1,318
Proved oil and natural gas properties	136,176
Goodwill	20,243
Accounts payable and accrued liabilities	(5,456)
Asset retirement obligations	(30,260)
Business acquisition, assets acquired (liabilities assumed), net	$ 122,021

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 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		$ 1,457	$ 45,183	$ 44,056
Asset sold, impairment charges			200
Assets and liabilities sold, previously held for sale			5,800
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
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	$ 44,100		$ 5,600

Risk Management (Schedule of Co

Risk Management (Schedule of Commodity Contracts) (Details)	12 Months Ended
	Dec. 31, 2015MMBTU$ / MBbls$ / MMBTUMMBbls
Oil [Member] | Swaps - 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume | MMBbls	366
Weighted Average Fixed Price | $ / MBbls	90.14
Natural Gas [Member] | Swaps - 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Natural Gas, Hedged Volume | MMBTU	39,894
Weighted Average Fixed Price	3.57
Natural Gas [Member] | Swaps Covering 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Natural Gas, Hedged Volume | MMBTU	21,900
Weighted Average Fixed Price	3.24
Natural Gas Liquids [Member] | Swaps - 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume | MMBbls	3.70
Weighted Average Fixed Price	9.14

Risk Management (Interest Rate

Risk Management (Interest Rate Swaps) (Details) - 1-Month LIBOR [Member] $ in Thousands	Dec. 31, 2015USD ($)
Interest Rate Swaps Covering January 2017 - December 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Amount	$ 100,000
Fixed Rate	1.039%
Interest Rate Swaps Covering January 2018 - September 2020
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Amount	$ 100,000
Fixed Rate	1.795%

Risk Management (Fair Value of

Risk Management (Fair Value of Derivatives) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset:
Derivative asset, fair value	$ 71,403	$ 135,401
Derivative asset, liability		(1,710)
Derivative asset	60,662	113,044
Long-term derivative asset	10,741	20,647
Net recorded fair value	71,403	133,691
Derivative Liabilities:
Derivative liability, fair value		1,710
Derivative liability, asset		(1,710)
Current Assets [Member]
Derivative Asset:
Derivative asset, fair value	60,662	114,754
Derivative asset, liability		(1,710)
Derivative asset	60,662	113,044
Long-term Derivative Asset [Member]
Derivative Asset:
Derivative asset, fair value	10,741	20,647
Long-term derivative asset	$ 10,741	20,647
Derivative Liability [Member]
Derivative Liabilities:
Derivative liability, fair value		1,710
Derivative liability, asset		$ (1,710)

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 136,667	$ 113,968	$ 85,341
Long-term Debt	688,614	1,027,349
Asset retirement obligation	176,933	105,773	103,173
Impairment losses	65,924
8.0% Senior Notes due 2019 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes, fair value	211,900	427,500
Long-term Debt	423,614	496,349
Long-Lived Assets Held and Used [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 86,900	103,100	76,300
Long-Lived Assets Held For Sale [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties		$ 200	$ 500

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	$ 71,403	$ 135,401
Derivative liability, fair value		1,710
Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	71,403
Recurring Basis [Member] | Commodity Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	70,356	135,401
Recurring Basis [Member] | Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	$ 1,047
Derivative liability, fair value		$ 1,710
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 asset, 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
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 asset, fair value
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 asset, fair value	$ 71,403
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	70,356	$ 135,401
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 asset, fair value	$ 1,047
Derivative liability, fair value		$ 1,710
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, 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
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 asset, fair value
Derivative liability, fair value

Fair Value Measurements (Fair59

Fair Value Measurements (Fair Value Hierarchy for Net Assets and Liabilities Measured Fair Value on Nonrecurring Basis) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill				$ 65,924
Nonrecurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill	$ 65,924
Long-lived assets	52,406	$ 88,844	$ 63,175
Total losses	$ 152,816	$ 103,282	$ 76,856
Nonrecurring 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]
Goodwill
Long-lived assets
Nonrecurring Basis [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
Nonrecurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets	$ 52,406	83,043	55,163
Long-Lived Assets Held and Used [Member] | Nonrecurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets	52,406	83,043	55,163
Total losses	$ 86,892	$ 103,118	$ 76,342
Long-Lived Assets Held and Used [Member] | Nonrecurring 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]
Long-lived assets
Long-Lived Assets Held and Used [Member] | Nonrecurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets	$ 52,406	$ 83,043	$ 55,163
Long-Lived Assets Held For Sale [Member] | Nonrecurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets		5,801	8,012
Total losses		$ 164	$ 514
Long-Lived Assets Held For Sale [Member] | Nonrecurring 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]
Long-lived assets
Long-Lived Assets Held For Sale [Member] | Nonrecurring Basis [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

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Asset retirement obligation, current	$ 2,930	$ 1,941

Asset Retirement Obligations (C

Asset Retirement Obligations (Changes in Aggregate Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Balance at beginning of period	$ 105,773	$ 103,173
Liabilities incurred and assumed in acquisitions	70,005	753
Accretion expense	5,531	4,835
Revisions in estimated cash flows	1,344	432
Settlements and divestitures	(5,720)	(3,420)
Balance at end of period	$ 176,933	$ 105,773

Long-Term Debt, Net (Narrative)

Long-Term Debt, Net (Narrative) (Details) $ in Thousands	Mar. 22, 2011	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity		$ 1,000,000
Senior secured credit facility, expiration date		Feb. 29, 2020
Debt instrument, covenant compliance, credit facility and letters of credit		we were in compliance with these financial covenants
Weighted average effective interest rate		3.73%	2.98%
Line of credit, borrowing base		$ 625,000
Credit facility outstanding		265,000	$ 531,000
Letters of credit outstanding, amount		400
Debt instrument, repurchase amount		$ 50,000
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
Borrowing Base Determination, Period One
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date		--04-01
Borrowing Base Determination, Period Two
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date		--10-01
8.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Senior unsecured notes, stated interest rate	8.00%
Senior unsecured notes, maturity date	2,019
Redemption price if change of control occurs	101.00%
Senior notes, carrying value		$ 426,022	$ 500,000
Debt instrument, repurchased face amount		74,000
Gain (loss) on repurchase of debt instrument		24,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity		$ 100,000

Long-Term Debt, Net (Long Term

Long-Term Debt, Net (Long Term Debt) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Credit facility outstanding		$ 265,000	$ 531,000
Long-term debt, Total		688,614	1,027,349
8.0% Senior Notes due 2019 [Member]
Principal outstanding		426,022	500,000
Unamortized discount and debt issuance costs	[1]	(5,116)	(7,652)
Unaccreted premium	[2]	2,708	4,001
Long-term debt, Total		$ 423,614	$ 496,349
Debt instrument, unamortized discount, imputed interest		8.87%	8.52%
Debt instrument, unaccreted expense, imputed interest		7.35%	7.62%
[1]	Imputed interest rate of 8.87% and 8.52% for 2015 and 2014, respectively.
[2]	Imputed interest rate of 7.35% and 7.62% for 2015 and 2014, respectively.

Long-Term Debt, Net (Redemption

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

Commitments and Contingencies (

Commitments and Contingencies (Schedule of Future Minimum Transportation Fees Payment) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies [Abstract]
2,016	$ 619
2,017	618
2,018	619
2,019	618
2,020	619
Thereafter	1,031
Balance as of December 31, 2015	$ 4,124

Owners' Equity (Narrative) (Det

Owners' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 25, 2016	Oct. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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
Public offering, price per common units		$ 36.86
Net proceeds from public offerings, including contributions		$ 208,500			$ 204,527
Contribution from general partner		$ 4,200	$ 91	$ 154	$ 4,508
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
Stockholders Equity Note [Line Items]
Distribution to unitholders, declared date	Jan. 25, 2016
Distribution to unitholders declared per unit	$ 0.075
Distribution to unitholders, amount	$ 3,900
Distribution to unitholders, record date	Feb. 5, 2016
Distribution to unitholders, payment date	Feb. 12, 2016
Executive officers and directors
Stockholders Equity Note [Line Items]
Common unitholders, units outstanding			4,956,505
Common Unitholders [Member]
Stockholders Equity Note [Line Items]
Common unitholders, units issued			48,871,399	48,572,019
Common unitholders, units outstanding			48,871,399

Owners' Equity (General Partner

Owners' Equity (General Partner Incentive Distributions with Respect to Specified Target Levels) (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Minimum Quarterly Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.7615
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]
Marginal Percentage Interest in Distributions, Limited Partner	98.00%
Marginal Percentage Interest in Distributions, General Partner	2.00%
First Target Distribution [Member] | Maximum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.875725
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	$ 0.951875
Second Target Distribution [Member] | Minimum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.875725
Thereafter [Member]
Distribution Made to Limited Partner [Line Items]
Marginal Percentage Interest in Distributions, Limited Partner	75.00%
Marginal Percentage Interest in Distributions, General Partner	25.00%
Thereafter [Member] | Minimum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.951875

Owners' Equity (Summary of Dist

Owners' Equity (Summary of Distributions Paid) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distribution Made to Limited Partner [Line Items]
Total Distribution	$ 100,979	$ 154,978	$ 140,126
Cash Distributions Period Covered October 1, 2014 - December 31, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid	Feb. 13, 2015
Distribution per Unit	$ 0.500
Total Distribution	$ 25,274
Cash Distributions Period Covered January 1, 2015 - March 31, 2015 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid	May 15, 2015
Distribution per Unit	$ 0.500
Total Distribution	$ 25,221
Cash Distributions Period Covered April 1, 2015 - June 30, 2015 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid	Aug. 14, 2015
Distribution per Unit	$ 0.500
Total Distribution	$ 25,243
Cash Distributions Period Covered July 1, 2015 - September 30, 2015 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid	Nov. 13, 2015
Distribution per Unit	$ 0.500
Total Distribution	$ 25,241
Cash Distributions Period Covered October 1, 2013 - December 31, 2013 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid		Feb. 14, 2014
Distribution per Unit		$ 0.771
Total Distribution		$ 38,696
Cash Distributions Period Covered January 1, 2014 - March 31, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid		May 15, 2014
Distribution per Unit		$ 0.772
Total Distribution		$ 38,716
Cash Distributions Period Covered April 1, 2014 - June 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid		Aug. 14, 2014
Distribution per Unit		$ 0.773
Total Distribution		$ 38,760
Cash Distributions Period Covered July 1, 2014 - September 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid		Nov. 14, 2014
Distribution per Unit		$ 0.774
Total Distribution		$ 38,806

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2015
Deferred taxes				$ (13,409)
Taxes Payable, Current	$ 11,657
(Loss) income before income taxes and equity in (loss) income of unconsolidated affiliates	236,022	$ (22,721)	$ 75,491
Loss subject to taxation	45,700
Belden [Member]
Deferred taxes				$ (13,409)
Taxes Payable, Current	$ 11,700

Income Taxes (Schedule of Compo

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 11,207
State	235
Current Federal, State and Local, Tax Expense (Benefit), Total	11,442
Deferred:
Federal	(12,482)
State	(803)
Deferred Federal, State and Local, Tax Expense (Benefit), Total	(13,285)
Income Tax Expense (Benefit), Total	$ (1,843)	$ 476	$ 133

Income Taxes (Schedule of Effec

Income Taxes (Schedule of Effective Income Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
U.S. statutory income tax rate	$ (15,986)
Impairment of Belden goodwill	15,989
Belden deferred tax liability released at conversion	(2,070)
State income taxes, net of federal tax benefit	224
Income Tax Expense (Benefit), Total	$ (1,843)	$ 476	$ 133

Discontinued Operations (Narrat

Discontinued Operations (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2015	Oct. 31, 2014	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 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				$ 1,457	$ 45,183	$ 44,056
Payment on lines of credit				$ 561,000	$ 159,000	$ 208,000
Utica East Ohio Midstream LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of equity method investments	$ 572,200
Gain (loss) on sale of investments			$ 246,700
Payment on lines of credit	25,000
Interest paid, discontinued operations	$ 1,500
Cardinal Gas Services, LLC [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of equity method investments		$ 161,100
Gain (loss) on sale of investments		$ 92,100

Discontinued Operations (Summar

Discontinued Operations (Summarized Financial Information Discontinued Operations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	[1]	Dec. 31, 2014		Dec. 31, 2013	[2]
Schedule of Equity Method Investments [Line Items]
Revenues		$ 93,726		$ 237,344	[2]	$ 56,888
Operating income		49,171		109,003	[2]	4,955
Net income		$ 49,525		109,660	[2]	$ 5,125
Utica East Ohio Midstream LLC
Schedule of Equity Method Investments [Line Items]
Current assets	[1]			98,061
Noncurrent assets	[1]			1,381,773
Total assets	[1]			1,479,834
Current liabilities	[1]			37,967
Owner's equity	[1]			1,441,867
Total liabilities and owner's equity	[1]			$ 1,479,834
[1]	Information is for UEO on a stand-alone basis through the date of divestiture.
[2]	Information is for UEO and Cardinal on a combined basis.

Earnings Per Limited Partner 74

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share Disclosure [Line Items]
(Loss) income from continuing operations																	$ (234,179)	$ 22,245	$ (75,624)
General partner 2% interest in loss from continuing operations																	4,684	(445)	1,513
Earnings attributable to unvested phantom units, continuing operations																	(1,076)	(1,723)	(2,006)
Limited partners' interest in loss from continuing operations																	$ (230,571)	$ 20,077	$ (76,117)
Earnings per limited partner unit (basic and diluted) (loss) income, continuing																	$ (4.72)	$ 0.41	$ (1.75)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest																	$ 255,512	$ 107,475	$ (603)
General partner's 2% interest in income from discontinued oeprations																	(5,110)	(2,150)	12
Limited partners' interest in income from discontinued operations																	$ 250,402	$ 105,325	$ (591)
Earnings per limited partner unit (basic and diluted) income, discontinued																	$ 5.13	$ 2.17	$ (0.01)
Net income (loss)	$ (71,264)	[1]	$ (9,838)	[1]	$ 164,102	[1]	$ (61,667)	[1]	$ 102,376	[1]	$ 42,620	[1]	$ (9,023)	[1]	$ (6,253)	[1]	$ 21,333	$ 129,720	$ (76,227)
General partners 2% interest in net income (loss)																	(426)	(2,595)	1,525
Earnings attributable to unvested phantom units																	(1,076)	(1,723)	(2,006)
Limited partners' interest in net (loss) income																	$ 19,831	$ 125,402	$ (76,708)
Earnings per share, basic and diluted																	$ 0.41	$ 2.58	$ (1.76)
Weighted average limited partner units outstanding - basic and diluted																	48,853	48,563	43,691
General partner interest in the Partnership, percentage																	2.00%
Earnings per limited partner unit (basic and diluted):
Basic	$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ 2.03		$ 0.85		$ (0.19)		$ (0.14)
Diluted	$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ 2.03		$ 0.85		$ (0.19)		$ (0.14)
Performance Units [Member]
Earnings per limited partner unit (basic and diluted):
Equity awards not included in computation of diluted net income (loss) per limited partner unit																		200	200
[1]	Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015 and gain on sale of our investment in Cardinal of $92.1 million in the fourth quarter of 2014.

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011	Oct. 31, 2015	Nov. 30, 2013
Related Party Transaction [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					$ 259,022
EnerVest, Ltd. [Member]
Related Party Transaction [Line Items]
Administrative fees paid to related party	$ 14,200	$ 12,100	$ 10,000
Direct expenses incurred and reimbursed to related party	17,200	17,000	17,100
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	200	400	200
Dividends from unconsolidated affiliates	$ 200	$ 300	$ 200
Barnett Shale [Member]
Related Party Transaction [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net						$ 65,974

Other Supplemental Informatio76

Other Supplemental Information (Supplemental Cash Flows and Non-Cash Transactions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental cash flows information:
Cash paid for interest	$ 48,344	$ 49,444	$ 45,355
Cash paid for income taxes		155	325
Proceeds from income tax refunds	(115)
Capitalized interest		5,741	7,276
Non-cash transactions:
Costs for additions to oil and natural gas properties	$ 5,212	$ 18,028	$ 19,450

Other Supplemental Informatio77

Other Supplemental Information (Schedule of Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Supplemental Information [Abstract]
Costs for additions to oil and natural gas properties	$ 5,212	$ 18,028
Lease operating expenses	10,576	9,701
Interest	7,298	8,649
Production and ad valorem taxes	6,763	5,683
VPP	3,984
General and administrative expenses	2,864	2,317
Current portion of ARO	2,930	1,941
Derivative settlements		280
Other	3,508	1,279
Total	$ 43,135	$ 47,878

Quarterly Data (Schedule of Qua

Quarterly Data (Schedule of Quarterly Data) (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended	3 Months Ended																6 Months Ended	12 Months Ended
		Oct. 31, 2014	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues			$ 47,952	[1]	$ 38,321	[1]	$ 44,456	[1]	$ 47,242	[1]	$ 70,175		$ 84,531		$ 89,360		$ 95,339			$ 177,971	$ 339,405	$ 315,312
Gross profit	[2]		15,683		13,945		18,549		21,396		39,126		54,105		59,433		65,451
Net (loss) income			$ (71,264)	[3]	$ (9,838)	[3]	$ 164,102	[3]	$ (61,667)	[3]	$ 102,376	[3]	$ 42,620	[3]	$ (9,023)	[3]	$ (6,253)	[3]		21,333	129,720	(76,227)
Limited partners' interest in net income (loss)																				$ 19,831	$ 125,402	$ (76,708)
Earnings per limited partner unit (basic and diluted):
Basic			$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ 2.03		$ 0.85		$ (0.19)		$ (0.14)
Diluted			$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ 2.03		$ 0.85		$ (0.19)		$ (0.14)
Utica East Ohio Midstream LLC
Earnings per limited partner unit (basic and diluted):
Gain (loss) on sale of investments																			$ 246,700
Cardinal Gas Services, LLC [Member]
Earnings per limited partner unit (basic and diluted):
Gain (loss) on sale of investments		$ 92,100
[1]	Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4).
[2]	Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.
[3]	Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015 and gain on sale of our investment in Cardinal of $92.1 million in the fourth quarter of 2014.

Supplementary Information on 79

Supplementary Information on Oil and Natural Gas Activities (Capitalized Costs Relating to Oil and Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Supplementary Information On Oil And Natural Gas Activities [Abstract]
Proved oil and natural gas properties	$ 2,694,354	$ 2,371,866
Unproved oil and natural gas properties	67,600	117,738
Total oil and natural gas properties	2,761,954	2,489,604
Accumulated depreciation, depletion and amortization	(971,499)	(778,679)
Net capitalized costs	$ 1,790,455	$ 1,710,925

Supplementary Information on 80

Supplementary Information on Oil and Natural Gas Activities (Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquisition of oil and natural gas properties:
Proved	$ 236,356		$ 59,602
Unproved	1,020		6,018
Exploration costs	2,193	$ 2,585	1,764
Development costs	55,109	103,840	108,486
Total	$ 294,678	$ 106,425	$ 175,870

Estimated Proved Oil, Natural81

Estimated Proved Oil, Natural Gas and Natural Liquids Reserves (Changes in Estimated Proved and Estimated Proved Developed Reserves) (Details) Mcfe in Thousands		12 Months Ended
		Dec. 31, 2015McfeMMBblsMMcf		Dec. 31, 2014McfeMMBblsMMcf		Dec. 31, 2013McfeMMBblsMMcf		Dec. 31, 2012McfeMMBblsMMcf
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance, energy | Mcfe	[1]	1,000,496		1,191,594		904,669
Revisions of previous estimates, energy | Mcfe	[1]	(268,522)	[2]	(246,856)	[3]	60,663
Purchase of minerals in place, energy | Mcfe	[1]	330,504		2,974		70,395
Extensions and discoveries, energy | Mcfe	[1]	100,647	[4]	127,571	[5]	218,112	[6]
Production, energy | Mcfe	[1]	(63,792)		(63,540)		(61,690)
Sales of minerals in place, energy | Mcfe	[1]	(2,580)		(11,247)		(555)
Proved developed and undeveloped reserves, ending balance, energy | Mcfe	[1]	1,096,753		1,000,496		1,191,594
Proved developed reserves (energy) | Mcfe	[1]	909,047		842,956		815,268		689,133
Proved undeveloped reserves (energy) | Mcfe	[1]	187,706		157,540		376,326		215,536
Reduction [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves | Mcfe						213,300
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	[7]	11,908,000		13,084,000		13,508,000
Revisions of previous estimates	[7]	(3,319,000)	[2]	(1,851,000)	[3]	(760,000)
Purchases of minerals in place	[7]	11,852,000		21,000		21,000
Extensions and discoveries	[7]	2,636,000	[4]	1,900,000	[5]	1,342,000	[6]
Production	[7]	(1,041,000)		(1,052,000)		(1,027,000)
Sales of minerals in place	[7]	(41,000)		(194,000)
Proved developed and undeveloped reserves, ending balance	[7]	21,995,000		11,908,000		13,084,000
Proved developed reserves (volume)	[7]	13,919,000		9,783,000		10,443,000		11,153,000
Proved undeveloped reserve (volume)	[7]	8,076,000		2,125,000		2,641,000		2,355,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | MMcf	[8]	712,192		819,680		609,546
Revisions of previous estimates | MMcf	[8]	(194,442)	[2]	(138,666)	[3]	36,214
Purchases of minerals in place | MMcf	[8]	214,578		1,515		67,291
Extensions and discoveries | MMcf	[8]	60,197	[4]	81,571	[5]	149,502	[6]
Production | MMcf	[8]	(43,592)		(43,363)		(42,651)
Sales of minerals in place | MMcf	[8]	(1,918)		(8,545)		(222)
Proved developed and undeveloped reserves, ending balance | MMcf	[8]	747,015		712,192		819,680
Proved developed reserves (volume) | MMcf	[8]	644,984		599,664		578,274		473,223
Proved undeveloped reserve (volume) | MMcf	[8]	102,031		112,528		241,406		136,323
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	[7]	36,143,000		48,902,000		35,679,000
Revisions of previous estimates	[7]	(9,028,000)	[2]	(16,180,000)	[3]	4,835,000
Purchases of minerals in place	[7]	7,468,000		222,000		496,000
Extensions and discoveries	[7]	4,106,000	[4]	5,767,000	[5]	10,093,000	[6]
Production	[7]	(2,326,000)		(2,311,000)		(2,146,000)
Sales of minerals in place	[7]	(69,000)		(257,000)		(55,000)
Proved developed and undeveloped reserves, ending balance	[7]	36,294,000		36,143,000		48,902,000
Proved developed reserves (volume)	[7]	30,091,000		30,766,000		29,056,000		24,832,000
Proved undeveloped reserve (volume)	[7]	6,203,000		5,377,000		19,846,000		10,847,000
Barnett Shale [Member]
Reserve Quantities [Line Items]
Volume produced from oil drilling success | Mcfe				78,200		177,100
Appalachian Basin [Member]
Reserve Quantities [Line Items]
Volume produced from oil drilling success | Mcfe				33,000
[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 Barnett Shale (120.7 Bcfe) and the Appalachian Basin (76.9 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2015 reserve estimates from prices used in our December 31, 2014 reserve estimates.
[3]	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.
[4]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (72.6 Bcfe) and the Appalachian Basin (16.9 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 (177.1 Bcfe).
[7]	Thousands of barrels.
[8]	Million cubic feet.

Standardized Measure of Disco82

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, 2015$ / MMBTU$ / item	Dec. 31, 2014$ / MMBTU$ / item	Dec. 31, 2013$ / MMBTU$ / item
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future net cash flows, annual discount rate	10.00%	10.00%	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 | $ / item	50.28	94.99	96.78
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 | $ / MMBTU	2.587	4.350	3.666

Standardized Measure of Disco83

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, 2015	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]
Future cash inflows	$ 3,285,271,000	$ 4,639,547,000	$ 4,998,790,000
Future production and development costs	(2,029,001,000)	(2,123,559,000)	(2,509,542,000)
Future income tax expenses	(7,769,000)	(18,266,000)	(22,091,000)
Future net cash flows	1,248,501,000	2,497,722,000	2,467,157,000
10% annual discount for estimated timing of cash flows	(712,051,000)	(1,404,419,000)	(1,427,372,000)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 536,450,000	$ 1,093,303,000	$ 1,039,785,000	$ 866,932,000
Future net cash flows, annual discount rate	10.00%	10.00%	10.00%

Standardized Measure of Disco84

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
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized Measure of Discontinued Future Net Cash Flows Relating to Proved Oil, Natural Gas and Natural Gas Liquids Reserves [Abstract]
Standardized measure at beginning of period	$ 1,093,303,000	$ 1,039,785,000	$ 866,932,000
Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	(68,479,000)	(216,972,000)	(194,942,000)
Net changes in prices and production costs	(682,598,000)	131,899,000	(1,264,000)
Extensions, discoveries and improved recovery, less related costs	26,082,000	113,127,000	113,714,000
Development costs incurred during the period	21,441,000	23,737,000	17,762,000
Revisions and other	(205,821,000)	(69,407,000)	53,427,000
Accretion of 10% timing discount	110,120,000	104,941,000	87,433,000
Changes in income taxes	4,362,000	1,725,000	(2,218,000)
Changes in estimated future development costs	19,925,000	(2,980,000)	1,692,000
Changes in timing and other	(31,118,000)	(28,853,000)	55,966,000
Purchase of minerals in place	250,646,000	4,376,000	41,810,000
Sales of minerals in place	(1,413,000)	(8,075,000)	(527,000)
Standardized measure of discounted future net cash flows	$ 536,450,000	$ 1,093,303,000	$ 1,039,785,000
Accretion timing discount rate	10.00%	10.00%	10.00%