Harvest Oil & Gas (HRST) 10-K 1 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 15, 2017	Jun. 30, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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	Accelerated Filer
Entity Common Stock, Shares Outstanding		49,368,869
Entity Public Float			$ 100,811,559

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 5,557	$ 20,415
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	39,629	24,285
Related party	745
Other	2,451	7,137
Derivative asset	201	60,662
Other current assets	3,718	3,057
Total current assets	52,301	115,556
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2016, $1,051,600; December 31, 2015, $971,499	1,497,211	1,790,455
Other property, net of accumulated depreciation and amortization; December 31, 2016, $1,002; December 31, 2015, $970	996	1,019
Restricted cash	52,076
Long-term derivative asset		10,741
Other assets	4,186	5,831
Total assets	1,606,770	1,923,602
Current liabilities:
Third party	31,700	43,135
Related party	5,797	5,952
Income taxes		11,657
Derivative liability	21,679
Total current liabilities	59,176	60,744
Asset retirement obligations	180,241	174,003
Long-term debt, net	606,948	688,614
Long-term derivative liability	955
Other long-term liabilities	1,043	1,682
Commitments and contingencies (Note 10)
Owners' equity:
Common unitholders - 49,055,214 units and 48,871,399 units issued and outstanding as of December 31, 2016 and 2015, respectively	776,158	1,011,509
General partner interest	(17,751)	(12,950)
Total owners' equity	758,407	998,559
Total liabilities and owners' equity	$ 1,606,770	$ 1,923,602

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and natural gas properties, accumulated depreciation, depletion and amortization	$ 1,051,600	$ 971,499
Other property, accumulated depreciation and amortization	$ 1,002	$ 970
Common Unitholders [Member]
Common unitholders, units issued	49,055,214	48,871,399
Common unitholders, units outstanding	49,055,214	48,871,399

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil, natural gas and natural gas liquids revenues	$ 182,696	$ 175,088	$ 334,729
Transportation and marketing-related revenues	2,198	2,883	4,676
Total revenues	184,894	177,971	339,405
Operating costs and expenses:
Lease operating expenses	103,371	99,626	105,781
Cost of purchased natural gas	1,497	1,988	3,533
Dry hole and exploration costs	651	3,695	6,726
Production taxes	7,386	6,784	11,976
Accretion expense on obligations	8,225	5,598	4,835
Depreciation, depletion and amortization	119,171	105,969	106,073
General and administrative expenses	33,637	38,994	44,955
Impairment of oil and natural gas properties	131,260	136,667	113,968
Impairment of goodwill		65,924
Loss (gain) on contracts	(3,185)	1,210
Gain on sales of oil and natural gas properties	(69)	(551)	(33,319)
Total operating costs and expenses	401,944	465,904	364,528
Operating loss	(217,050)	(287,933)	(25,123)
Other income (expense), net:
Gain (loss) on derivatives, net	(35,950)	78,145	99,720
Interest expense	(42,487)	(50,336)	(52,578)
Gain on early extinguishment of debt	47,695	24,024
Other income, net	2,522	78	702
Total other income (expense), net	(28,220)	51,911	47,844
Income (loss) from continuing operations before income taxes	(245,270)	(236,022)	22,721
Income taxes	2,375	1,843	(476)
Income (loss) from continuing operations	(242,895)	(234,179)	22,245
Income from discontinued operations		255,512	107,475
Net income (loss)	$ (242,895)	$ 21,333	$ 129,720
Earnings per limited partner unit (basic and diluted):
Earnings per limited partner unit basic, continued	$ (4.85)	$ (4.72)	$ 0.41
Earnings per limited partner unit diluted, continued	(4.85)	(4.72)	0.41
Earnings per limited partner unit basic, discontinued		5.13	2.17
Earnings per limited partner unit diluted, discontinued		5.13	2.17
Earnings per limited partner unit basic	(4.85)	0.41	2.58
Earnings per limited partner unit diluted	$ (4.85)	$ 0.41	$ 2.58
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding, basic	49,048	48,853	48,563
Weighted average limited partner units outstanding, diluted	49,048	48,853	48,563
Distributions declared per common unit		$ 1.575	$ 2.819

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (242,895)	$ 21,333	$ 129,720
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Income from discontinued operations		(255,512)	(107,475)
Accretion expense on obligations	8,225	5,598	4,835
Amortization of volumetric production payment liability	(4,108)	(1,196)
Depreciation, depletion and amortization	119,171	105,969	106,073
Equity-based compensation	6,611	12,001	19,289
Impairment of oil and natural gas properties	131,260	136,667	113,968
Impairment of goodwill		65,924
Gain on sales of oil and natural gas properties	(69)	(551)	(33,319)
Loss (gain) on derivatives, net	35,950	(78,145)	(99,720)
Cash settlements of matured derivatives contracts	54,884	140,657	5,313
Gain on early extinguishment of debt	(47,695)	(24,024)
Deferred taxes	(404)	(13,285)
Other	2,523	4,487	5,703
Changes in operating assets and liabilities, net of effects of amounts acquired:
Accounts receivable	(11,403)	14,850	3,275
Other current assets	(361)	511	(1,203)
Accounts payable and accrued liabilities	(5,862)	(4,067)	2,368
Income taxes	(11,657)	10,683
Other, net	(295)	(245)	(627)
Net cash flows provided by operating activities from continuing operations	33,875	141,655	148,200
Net cash flows used in operating activities from discontinued operations		(372)
Net cash flows provided by operating activities	33,875	141,283	148,200
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net of cash acquired		(250,357)
Additions to oil and natural gas properties	(15,258)	(67,923)	(102,761)
Prepaid drilling costs			(2,501)
Proceeds from sale of oil and natural gas properties	54,509	1,457	45,183
Restricted cash	(52,076)	33,768	(33,768)
Cash settlements from acquired derivative contracts	3,003	2,615
Other	56	73	48
Net cash flows used in investing activities from continuing operations	(9,766)	(280,367)	(93,799)
Net cash flows provided by investing activities from discontinued operations		572,160	46,985
Net cash flows (used in) provided by investing activities	(9,766)	291,793	(46,814)
Cash flows from financing activities:
Long-term debt borrowings	57,000	295,000	209,000
Repayment of long-term debt borrowings	(57,000)	(561,000)	(159,000)
Redemption of 8% Senior Notes due 2019	(34,978)	(49,954)
Loan costs paid	(121)	(4,074)
Contributions from general partner		91	154
Distributions	(3,868)	(100,979)	(154,978)
Other			(5)
Net cash flows used in financing activities	(38,967)	(420,916)	(104,829)
(Decrease) increase in cash and cash equivalents	(14,858)	12,160	(3,443)
Cash and cash equivalents - beginning of year	20,415	8,255	11,698
Cash and cash equivalents - end of year	$ 5,557	$ 20,415	$ 8,255

Consolidated Statements of Chan

Consolidated Statements of Changes in Owners' Equity - USD ($) $ in Thousands	Common Unitholders [Member]	General Partner Interest [Member]	Total
Beginning Balance at Dec. 31, 2013	$ 1,083,718	$ (11,785)	$ 1,071,933
Contributions from general partner		154	154
Distributions	(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
Ending Balance at Dec. 31, 2014	1,077,826	(11,713)	1,066,113
Contributions from general partner		91	91
Distributions	(98,985)	(1,994)	(100,979)
Equity-based compensation	11,761	240	12,001
Net income (loss)	20,907	426	21,333
Ending Balance at Dec. 31, 2015	1,011,509	(12,950)	998,559
Distributions	(3,793)	(75)	(3,868)
Equity-based compensation	6,479	132	6,611
Net income (loss)	(238,037)	(4,858)	(242,895)
Ending Balance at Dec. 31, 2016	$ 776,158	$ (17,751)	$ 758,407

Organization and Nature of Busi

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2016
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
ORGANIZATION AND NATURE OF BUSINESS	NOTE 1. ORGANIZATION AND NATURE OF BUSINESS  EV Energy Partners, L.P. (the “Parent”) and its wholly owned subsidiaries (collectively, the “Partnership”) are a publicly held limited partnership. The Partnership’s general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of its general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates also have a significant interest in the Partnership through their 71.25 % ownership of EV Energy GP which, in turn, owns a 2 % general partner interest in the Partnership and all of its incentive distribution rights.  The Partnership operates 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, 2016
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, 2016 and 2015, we did no t have any reserves for doubtful accounts, and we did no t 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 $ 20.9 million and $ 67.6 million as of December 31, 2016 and 2015, 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 2016, 2015 and 2014, we recorded dry hole and exploration costs of $ 0.7 million, $ 3.7 million and $ 6.7 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 2016, 2015 and 2014, we recorded impairment charges of $89.5 million, $ 86.9 million and $ 103.3 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). The $89.5 million of impairment for 2016 related to oil and natural gas properties in the Barnett Shale which were sold during December 2016 (see Note 5). Since December 31, 2016, commodity prices have continued to fluctuate. If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have 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 2016, 2015 and 2014, we recorded impairment charges of $41.8 million, $ 49.8 million and $ 10.7 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, 2016 or 2015.  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, 2016, 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 2016, three customers accounted for 18.5% , 13.4% and 10.4% , respectively, of our consolidated oil, natural gas and natural gas liquids revenues. 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, 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. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to implement ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We are in the initial stages of our evaluation of the impact of the new standard on our accounting policies, processes, system requirements and financial reporting. Based on the evaluation performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account previously identified, and we expect the timing of our revenue to remain the same. We will continue to assess the impact of adopting this ASU.  In August 2014, the FASB issued ASU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this ASU did not have a material impact on our consolidated financial statements.  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. The adoption of this ASU did not have a material impact on our consolidated financial statements.  In February 2016, the FASB issued ASU No. 2016-02 , Leases . The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. We are in the initial stages of our evaluation of the impact of this new standard on our accounting policies, processes, system requirements and financial reporting. In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation . This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016–15, Statement of Cash Flows . This ASU addresses certain cash flow issues with the objective of reducing the existing diversity in practice in how the cash receipts and cash payments are presented and classified in the statement of cash flows. The provisions of ASU 2016–15 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.  In November 2016, the FASB issued ASU No. 2016-18: Statement of Cash Flows– Restricted Cash . The main objective of ASU 2016-18 is to address the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows. The amendments in ASU 2016-18 require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Thus, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. For public entities, ASU 2016-18 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.  No other new accounting pronouncements issued or effective during the year ended December 31, 2016 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, 2016
EQUITY-BASED COMPENSATION [Abstract]
EQUITY-BASED COMPENSATION	NOTE 3. EQUITY–BASED COMPENSATION  EV Management has two long–term incentive plans, the 2006 Long-Term Incentive Plan (the “2006 Plan”) and the 2016 Long-Term Incentive Plan (the “2016 Plan” and together, the “Plans”) for employees, consultants and directors of EV Management and its affiliates who perform services for us. The 2006 Plan expired on September 20, 2016, and on August 30, 2016, the unitholders approved the adoption of the 2016 Plan, which replaced the 2006 Plan with respect to future awards. The 2016 Plan provides for the issuance of up to 5,000,000 units and allows for the award of unit options, phantom units, performance units, restricted units and deferred equity rights. As of December 31, 2016, the aggregate amount of our common units that may be awarded under the 2016 Plan was 4.0 million units. The compensation committee of the board of directors administers the Plans.  Phantom Units  Equity Awards  We account for phantom units 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:    2016 2015 2014  Weighted average fair value of phantom units $ 2.05 $ 2.61 $ 22.77  Expected volatility 83.41% 62.33% 34.52%  Risk–free interest rate 1.30% 1.13% 0.87%  Dividend yield 0.0% 0.0% 0.0%  Expected life (years) 4.0 4.1 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, 2015 1,689,248 $ 13.39  Granted 951,494 2.05  Vested (214,807) 39.29  Forfeited (200,058) 10.49  Nonvested phantom units as of December 31, 2016 2,225,877 $ 6.31  The total grant date fair value of the phantom units vested in 2016, 2015 and 2014 was $ 8.4 million, $ 15.2 million and $ 11.9 million, respectively.  We recognized compensation cost related to these phantom units of $ 6.6 million, $ 11.8 million and $ 13.9 million in 2016, 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.  As of December 31, 2016, there was $ 9.2 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.4 years.  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. These performance units were fully vested as of January 2015.  The total grant date fair value of the performance units vested in 2015 and 2014 was $ 1.6 million and $ 1.4 million, respectively.  We recognized compensation cost related to our performance units of $0.2 million and $ 5.4 million in 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
ACQUISITIONS [Abstract]
ACQUISITIONS	NOTE 4. ACQUISITIONS  2017  On January 31, 2017, we acquired a 5.8% working interest in acreage in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the $52.1 million of proceeds from the divestiture of our Barnett Shale natural gas properties (see Note 5) and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.  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 we recognized $5.6 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for 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 for 2015; and  · we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million, and we recognized $4.5 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for 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 were obligated under these agreements to produce and deliver to the purchaser its portion of 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 were inadequate to deliver the natural gas provided for in the VPP, we had an obligation to make up the shortfall in accordance with the provisions of the agreements.  At December 31, 2016, we had no remaining obligation under these agreements and no liability 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. At December 31, 2015, the remaining obligation under these agreements was approximately 1.9 Bcf of natural gas, and we had 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 2016 and 2015, we recorded $0.1 million and $0.1 million, respectively, of accretion expense related to this VPP obligation.  We accounted for these acquisitions as business combinations. 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.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2016
Divestitures [Abstract]
Divestitures	NOTE 5. DIVESTITURES  2016  In December 2016, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of a portion of our Barnett Shale natural gas properties, and our share of the proceeds was $52.1 million (before post-closing adjustments) . Also, during 2016, we received proceeds of $2.4 million for the sale of other oil and gas properties.  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 7). Operating results related to these properties were included in our exploration and production segment.  In addition, we closed on the sale of 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. 

Risk Management

Risk Management	12 Months Ended
	Dec. 31, 2016
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, 2016, we had entered into oil, natural gas and natural gas liquids derivatives with the following terms:     Weighted Weighted Weighted  Average Average Average  Hedged Fixed Floor Ceiling  Period Covered Volume Price Price Price  Oil (MBbls):  Swaps – 2017 365.0 $ 52.85 $ - $ -   Natural Gas (MmmBtus):  Swaps – 2017 32,850.0 3.07 - -  Collars – 2017 10,950.0 - 2.75 3.27  Swaps – 2018 4,500.0 3.46 - -   Natural Gas Liquids (MBbls):  Swaps – 2017 766.5 16.14 - -  As of December 31, 2016, 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, 2016:  Derivative asset $ 201 $ - $ 201  Long–term derivative asset - - -  Total $ 201 $ - $ 201   As of December 31, 2015:  Derivative asset $ 60,662 $ - $ 60,662  Long–term derivative asset 10,741 - 10,741  Total $ 71,403 $ - $ 71,403      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, 2016:  Derivative liability $ 21,679 $ - $ 21,679  Long–term derivative liability 955 - 955  Total $ 22,634 $ - $ 22,634  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, 2016 and 2015, 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, 2016
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, 2016:  Assets:  Oil, natural gas and natural gas liquids derivatives $ - $ - $ - $ -  Interest rate swaps 201 - 201 -  $ 201 $ - $ 201 $ -   Liabilities:  Oil, natural gas and natural gas liquids derivatives $ 22,588 $ - $ 22,588 $ -  Interest rate swaps 46 - 46 -  $ 22,634 $ - $ 22,634 $ -   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 $ -  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. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts to reflect counterparty credit quality and/or the effect of our own creditworthiness. These assumed credit risk adjustments are based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation techniques or related inputs in 2016.  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  Long–lived Assets Held and Used  We did not incur any impairment charges in 2016 for any of our oil and natural gas properties that were held and used as December 31, 2016. 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 and $103.1 million in 2015 and 2014, respectively, to write down oil and natural gas properties to their fair value. These impairment charges were included in earnings in 2015 and 2014, 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, we incurred additional impairment charges of $0.2 million to write down assets held for sale to their fair value. These impairment charges were included in earnings for 2014.  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, the 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, restricted cash, 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, 2016 and December 31, 2015, the estimated fair value of our senior notes due April 2019 was $ 242.6 million and $ 211.9 million, respectively, which differs from the carrying value of $341.9 million and $423.6 million, respectively. T he fair value of the senior notes due April 2019 was determined using Level 2 inputs .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 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  Liabilities incurred 1,223  Accretion expense 8,101  Revisions in estimated cash flows 820  Settlements and divestitures (3,601)  Balance as of December 31, 2016 $ 183,476  As of December 31, 2016 and 2015, $3.2 million and $ 2.9 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, 2016
LONG-TERM DEBT [Abstract]
LONG-TERM DEBT	NOTE 9. LONG–TERM DEBT, NET  Long–term debt, net consisted of the following as of December 31:     2016 2015   Credit facility $ 265,000 $ 265,000  8.0% senior notes due April 2019:  Principal outstanding 343,348 426,022  Unamortized discount and debt issuance costs (1) (2,946) (5,116)  Unaccreted premium (2) 1,546 2,708  341,948 423,614  Total $ 606,948 $ 688,614 _____________ (1) Imputed interest rate of 8.99% and 8.87% for 2016 and 2015, respectively.  (2) Imputed interest rate of 7.22% and 7.35% for 2016 and 2015, respectively.  Credit Facility  As of December 31, 2016, 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, 2016, we have a $0.3 million letter of credit outstanding.  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 3.75 % and 3.73 % at December 31, 2016 and 2015, 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, 2016, the borrowing base under the facility was $ 450.0 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.  In April 2016, we entered into an amendment to our credit facility that eased leverage covenants and added an interest coverage ratio. Specifically, the amendment:  · decreased the borrowing base to $450.0 million;  · changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0 , (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0 ;  · changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0 , (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0 ;  · added an EBITDAX to cash interest expense ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0 , (b) for the fiscal quarters ending December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0 ;  · allowed for up to $35.0 million of cash, reduced dollar for dollar by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due April 2019; and  · limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.  As of December 31, 2016, we were in compliance with these financial covenants .  8.0% Senior Notes due April 2019  Our 8.0% senior unsecured notes due April 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 2016, we redeemed $82.7 million of the Notes for $35.0 million, resulting in a gain on the early extinguishment of debt of $47.7 million. 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  2017 100.00%  2018 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, 2016
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, 2016 and 2015.  We are subject to firm agreements for the future transportation and processing of natural gas. We are obligated to transport minimum daily natural gas volumes. As of December 31, 2016, our future minimum transportation fees under these agreements are as follows for the years ended December 31:     2017 $ 3,603  2018 3,324  2019 2,765  2020 1,604  2021 1,394  Thereafter 2,701  $ 15,391  

Owners' Equity

Owners' Equity	12 Months Ended
	Dec. 31, 2016
OWNERS' EQUITY [Abstract]
OWNERS' EQUITY	NOTE 11. OWNERS’ EQUITY  Units Outstanding  At December 31, 2016, owner’s equity consists of 49,055,214 common units outstanding (including 5,032,399 common units held by our executive officers and directors), collectively representing a 98 % limited partnership interest in us and a 2 % general partnership interest.  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  In the future, we intend 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, 2016 and 2015:     Date Paid Period Covered Distribution per Unit Total Distribution  February 12, 2016 October 1, 2015 – December 31, 2015 $ 0.075 $ 3,868  $ 3,868   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  During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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 for the year ended December 31, 2015, $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)  Our tax filings for four years are subject to examination by federal and state tax authorities where we conduct our business. These examinations may result in assessments of additional tax that are resolved with the authorities or through the courts. We have evaluated whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions we have taken are supportable by existing laws and related interpretations, we believe there are no material uncertain tax positions to consider.  In 2016, we recorded approximately $2.4 million of tax benefits as a result of tax refunds and lower taxes. 

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2016
DISCONTINUED OPERATIONS [Abstract]
DISCONTINUTED OPERATIONS	NOTE 13. DISCONTINUED OPERATIONS  Our midstream segment, which consisted of our investments in Utica East Ohio Midstream LLC (“ UEO”) and Cardinal Gas Services, LLC (“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 these sales, the Partnership no longer operates in the midstream segment.  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:     2015 (1) 2014 (2)  Revenues $ 93,726 $ 237,344  Operating income 49,171 109,003  Net income 49,525 109,660 _____________ (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, 2016
EARNINGS PER LIMITED PARTNER UNIT [Abstract]
EARNINGS 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:     2016 2015 2014  Income (loss) from continuing operations $ (242,895) $ (234,179) $ 22,245  General partner's 2% interest in income (loss) from  continuing operations 4,858 4,684 (445)  Earnings attributable to unvested phantom units - (1,076) (1,723)  Limited partners' interest in income (loss) from continuing  operations $ (238,037) $ (230,571) $ 20,077   Earnings per limited partner unit (basic and diluted) $ (4.85) $ (4.72) $ 0.41   Income (loss) from discontinued operations $ - $ 255,512 $ 107,475  General partner's 2% interest in income (loss) from  discontinued operations - (5,110) (2,150)  Earnings attributable to unvested phantom units - - -  Limited partners' interest in income (loss) from  discontinued operations $ - $ 250,402 $ 105,325   Earnings per limited partner unit (basic and diluted) $ - $ 5.13 $ 2.17   Net income (loss) $ (242,895) $ 21,333 $ 129,720  General partner's 2% interest in net income (loss) 4,858 (426) (2,595)  Earnings attributable to unvested phantom units - (1,076) (1,723)  Limited partners' interest in net income (loss) $ (238,037) $ 19,831 $ 125,402   Earnings per limited partner unit (basic and diluted) $ (4.85) $ 0.41 $ 2.58   Weighted average limited partner units outstanding  (basic and diluted) 49,048 48,853 48,563  As of December 31, 2016 and 2015, there are no unearned performance units outstanding. As of December 31, 2014, 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, 2016
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 15. RELATED PARTY TRANSACTIONS  Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $15.9 million, $14.2 million and $12.1 million in 2016, 2015 and 2014, 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 2016, 2015 and 2014, we reimbursed EnerVest approximately $21.2 million, $17.2 million and $17.0 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.  As of December 31, 2016, we owed EnerVest Operating $5.8 million and partnerships managed by EnerVest owed us $0.7 million.  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 entitles 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 $0.1 million, $0.2 million and $0.4 million of income in 2016, 2015 and 2014, respectively, and we received $0.1 million, $0.2 million and $0.3 million of distributions in 2016, 2015 and 2014, respectively.

Other Supplemental Information

Other Supplemental Information	12 Months Ended
	Dec. 31, 2016
OTHER SUPPLEMENTAL INFORMATION [Abstract]
OTHER SUPPLEMENTAL INFORMATION	NOTE 16. OTHER SUPPLEMENTAL INFORMATION  Supplemental cash flows and non–cash transactions were as follows as of and for the years ended December 31:     2016 2015 2014  Supplemental cash flows information:  Cash paid for interest, net of capitalized interest of $5,741  at December 31, 2014 $ 39,807 $ 48,344 $ 49,444  Cash (refunded) paid for income taxes 10,942 (115) 155   Non–cash transactions:  Costs for additions to oil and natural gas properties in accounts  payable and accrued liabilities 668 5,212 18,028  Post-closing adjustments for sales of oil and natural gas properties  in accounts payable and accrued liabilities 1,752 - -  Accounts payable and accrued liabilities consisted of the following as of December 31:     2016 2015   Costs for additions to oil and natural gas properties $ 668 $ 5,212  Lease operating expenses 9,835 10,576  Interest 6,029 7,298  Production and ad valorem taxes 7,382 6,763  VPP - 3,984  General and administrative expenses 3,095 2,864  Current portion of ARO 3,235 2,930  Derivative settlements 106 -  Other 1,350 3,508  Total $ 31,700 $ 43,135 

Quarterly Data

Quarterly Data	12 Months Ended
	Dec. 31, 2016
Quarterly Data [Abstract]
Quarterly Data	NOTE 17. QUARTERLY DATA (UNAUDITED)      First Second Third Fourth  Quarter Quarter Quarter Quarter  2016  Revenues $ 38,250 $ 42,831 $ 51,372 $ 52,441  Gross profit (1) 7,328 14,776 23,240 27,296  Net (loss) income (2) (29,000) (28,993) (19,230) (165,672)  Net (loss) income per limited partner unit:  Basic $ (0.58) $ (0.58) $ (0.38) $ (3.31)  Diluted $ (0.58) $ (0.58) $ (0.38) $ (3.31)   2015  Revenues (3) $ 47,242 $ 44,456 $ 38,321 $ 47,952  Gross profit (1) 21,396 18,549 13,945 15,683  Net (loss) income (4) (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) _____________ (1) Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.  (2) Includes impairment charges of $131.3 million , primarily in the fourth quarter of 2016 . Of this amount, $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the expected present value of the future net cash flows. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale.  (3) Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4).  (4) Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015.

Supplementary Information on Oi

Supplementary Information on Oil and Natural Gas Activities	12 Months Ended
	Dec. 31, 2016
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:      2016 2015  Proved oil and natural gas properties $ 2,527,927 $ 2,694,354  Unproved oil and natural gas properties 20,884 67,600  2,548,811 2,761,954  Accumulated depreciation, depletion and amortization (1,051,600) (971,499)  Net capitalized costs $ 1,497,211 $ 1,790,455  Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:     2016 2015 2014  Acquisition of oil and natural gas properties:  Proved $ - $ 236,356 $ -  Unproved - 1,020 -  Exploration costs 651 2,193 2,585  Development costs 10,712 55,109 103,840  Total $ 11,363 $ 294,678 $ 106,425 

Estimated Proved Oil, Natural G

Estimated Proved Oil, Natural Gas and Natural Liquids Reserves	12 Months Ended
	Dec. 31, 2016
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, 2016 and 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 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, 2013 13,084 819,680 48,902 1,191,594  Revisions of previous estimates (4) (1,851) (138,666) (16,180) (246,856)  Purchases of minerals in place 21 1,515 222 2,974  Extensions and discoveries (5) 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 (6) (3,319) (194,442) (9,028) (268,522)  Purchases of minerals in place 11,852 214,578 7,468 330,504  Extensions and discoveries (7) 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  Revisions of previous estimates (8) (8,163) (57,723) (1,223) (114,041)  Extensions and discoveries (9) 61 10,255 736 15,038  Production (1,216) (49,333) (2,331) (70,612)  Sales of minerals in place (10) (85) (74,916) (81) (75,919)  As of December 31, 2016 12,592 575,298 33,395 851,219   Proved developed reserves:  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  December 31, 2016 11,954 523,113 28,218 764,149   Proved undeveloped reserves:  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  December 31, 2016 638 52,185 5,177 87,070 _____________ (1) Thousands of barrels.  (2) Million cubic feet.  (3) Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent .  (4) Revisions were primarily attributable to 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.  (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) 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.  (7) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 72.6 Bcfe) and the Appalachian Basin ( 16.9 Bcfe).  (8) Revisions were primarily attributable to reductions in the Appalachian Basin ( 51.8 Bcfe), the Barnett Shale ( 39.9 Bcfe) and Central Texas ( 13.5 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates from prices used in our December 31, 2015 reserve estimates.  (9) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 13.0 Bcfe).  (10) Sales of minerals in place were primarily associated with the sale of a portion of our Barnett Shale natural gas properties ( 74.2 Bcfe) in December 2016. 

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, 2016
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:     2016 2015 2014  Future cash inflows $ 2,261,520 $ 3,285,271 $ 4,639,547  Future production and development costs (1,480,900) (2,029,001) (2,123,559)  Future income tax expenses (5,442) (7,769) (18,266)  Future net cash flows 775,178 1,248,501 2,497,722  10% annual discount for estimated timing of cash flows (404,061) (712,051) (1,404,419)  Standardized measure of discounted future net cash flows $ 371,117 $ 536,450 $ 1,093,303  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, 2016, 2015 and 2014 were $42.75 per Bbl of oil, $2.481 per MMBtu of natural gas; $ 50.28 per Bbl of oil, $2.587 per MMBtu of natural gas; and $ 94.99 per Bbl of oil, $ 4.35 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:      2016 2015 2014  Standardized measure at beginning of period $ 536,450 $ 1,093,303 $ 1,039,785  Sales and transfers of oil, natural gas and natural gas liquids produced,  net of production costs (71,939) (68,479) (216,972)  Net changes in prices and production costs (83,146) (682,598) 131,899  Extensions, discoveries and improved recovery, less related costs 1,712 26,082 113,127  Development costs incurred during the period 2,065 21,441 23,737  Revisions and other (23,328) (205,821) (69,407)  Accretion of 10% timing discount 53,998 110,120 104,941  Changes in income taxes 1,093 4,362 1,725  Changes in estimated future development costs 3,976 19,925 (2,980)  Changes in timing and other (26,920) (31,118) (28,853)  Purchase of minerals in place - 250,646 4,376  Sales of minerals in place (22,844) (1,413) (8,075)  Standardized measure of discounted future net cash flows $ 371,117 $ 536,450 $ 1,093,303  

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015, we did no t have any reserves for doubtful accounts, and we did no t 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 $ 20.9 million and $ 67.6 million as of December 31, 2016 and 2015, 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 2016, 2015 and 2014, we recorded dry hole and exploration costs of $ 0.7 million, $ 3.7 million and $ 6.7 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	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 2016, 2015 and 2014, we recorded impairment charges of $89.5 million, $ 86.9 million and $ 103.3 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). The $89.5 million of impairment for 2016 related to oil and natural gas properties in the Barnett Shale which were sold during December 2016 (see Note 5). Since December 31, 2016, commodity prices have continued to fluctuate. If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have 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 2016, 2015 and 2014, we recorded impairment charges of $41.8 million, $ 49.8 million and $ 10.7 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, 2016 or 2015.  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).
Earnings 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, 2016, 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 2016, three customers accounted for 18.5% , 13.4% and 10.4% , respectively, of our consolidated oil, natural gas and natural gas liquids revenues. 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, 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. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to implement ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We are in the initial stages of our evaluation of the impact of the new standard on our accounting policies, processes, system requirements and financial reporting. Based on the evaluation performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account previously identified, and we expect the timing of our revenue to remain the same. We will continue to assess the impact of adopting this ASU.  In August 2014, the FASB issued ASU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this ASU did not have a material impact on our consolidated financial statements.  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. The adoption of this ASU did not have a material impact on our consolidated financial statements.  In February 2016, the FASB issued ASU No. 2016-02 , Leases . The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. We are in the initial stages of our evaluation of the impact of this new standard on our accounting policies, processes, system requirements and financial reporting. In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation . This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016–15, Statement of Cash Flows . This ASU addresses certain cash flow issues with the objective of reducing the existing diversity in practice in how the cash receipts and cash payments are presented and classified in the statement of cash flows. The provisions of ASU 2016–15 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.  In November 2016, the FASB issued ASU No. 2016-18: Statement of Cash Flows– Restricted Cash . The main objective of ASU 2016-18 is to address the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows. The amendments in ASU 2016-18 require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Thus, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. For public entities, ASU 2016-18 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.  No other new accounting pronouncements issued or effective during the year ended December 31, 2016 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, 2016
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) - Equity Awards [Member]	12 Months Ended
	Dec. 31, 2016
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, 2015 1,689,248 $ 13.39  Granted 951,494 2.05  Vested (214,807) 39.29  Forfeited (200,058) 10.49  Nonvested phantom units as of December 31, 2016 2,225,877 $ 6.31 
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:    2016 2015 2014  Weighted average fair value of phantom units $ 2.05 $ 2.61 $ 22.77  Expected volatility 83.41% 62.33% 34.52%  Risk–free interest rate 1.30% 1.13% 0.87%  Dividend yield 0.0% 0.0% 0.0%  Expected life (years) 4.0 4.1 4.0 

Acquisitions (Tables)

Acquisitions (Tables) - Appalachian Basin, San Juan Basin, Michigan and Austin Chalk Properties [Member]	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
Pro Forma Revenues and Net Income (Loss)	   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 in Connection with Acquisitions	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, 2016
RISK MANAGEMENT [Abstract]
Commodity Contracts	 As of December 31, 2016, we had entered into oil, natural gas and natural gas liquids derivatives with the following terms:     Weighted Weighted Weighted  Average Average Average  Hedged Fixed Floor Ceiling  Period Covered Volume Price Price Price  Oil (MBbls):  Swaps – 2017 365.0 $ 52.85 $ - $ -   Natural Gas (MmmBtus):  Swaps – 2017 32,850.0 3.07 - -  Collars – 2017 10,950.0 - 2.75 3.27  Swaps – 2018 4,500.0 3.46 - -   Natural Gas Liquids (MBbls):  Swaps – 2017 766.5 16.14 - - 
Interest Rate Swaps	As of December 31, 2016, 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, 2016:  Derivative asset $ 201 $ - $ 201  Long–term derivative asset - - -  Total $ 201 $ - $ 201   As of December 31, 2015:  Derivative asset $ 60,662 $ - $ 60,662  Long–term derivative asset 10,741 - 10,741  Total $ 71,403 $ - $ 71,403      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, 2016:  Derivative liability $ 21,679 $ - $ 21,679  Long–term derivative liability 955 - 955  Total $ 22,634 $ - $ 22,634 

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
FAIR VALUE MEASUREMENTS [Abstract]
Fair Value Hierarchy for Assets and Liabilities Measured at 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, 2016:  Assets:  Oil, natural gas and natural gas liquids derivatives $ - $ - $ - $ -  Interest rate swaps 201 - 201 -  $ 201 $ - $ 201 $ -   Liabilities:  Oil, natural gas and natural gas liquids derivatives $ 22,588 $ - $ 22,588 $ -  Interest rate swaps 46 - 46 -  $ 22,634 $ - $ 22,634 $ -   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 $ - 
Fair Value Hierarchy for Assets and Liabilities Measured at 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 

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
ASSET RETIREMENT OBLIGATIONS [Abstract]
Changes in Aggregate Asset Retirement Obligation	The changes in the aggregate ARO are as follows:     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  Liabilities incurred 1,223  Accretion expense 8,101  Revisions in estimated cash flows 820  Settlements and divestitures (3,601)  Balance as of December 31, 2016 $ 183,476 

Long-Term Debt, Net (Tables)

Long-Term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2016
LONG-TERM DEBT [Abstract]
Long Term Debt	Long–term debt, net consisted of the following as of December 31:     2016 2015   Credit facility $ 265,000 $ 265,000  8.0% senior notes due April 2019:  Principal outstanding 343,348 426,022  Unamortized discount and debt issuance costs (1) (2,946) (5,116)  Unaccreted premium (2) 1,546 2,708  341,948 423,614  Total $ 606,948 $ 688,614 _____________ (1) Imputed interest rate of 8.99% and 8.87% for 2016 and 2015, respectively.  (2) Imputed interest rate of 7.22% and 7.35% for 2016 and 2015, 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  2017 100.00%  2018 and thereafter 100.00% 

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
COMMITMENTS AND CONTINGENCIES [Abstract]
Schedule of Future Minimum Transportation Fees	We are subject to firm agreements for the future transportation and processing of natural gas. We are obligated to transport minimum daily natural gas volumes. As of December 31, 2016, our future minimum transportation fees under these agreements are as follows for the years ended December 31:     2017 $ 3,603  2018 3,324  2019 2,765  2020 1,604  2021 1,394  Thereafter 2,701  $ 15,391 

Owners' Equity (Tables)

Owners' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015:     Date Paid Period Covered Distribution per Unit Total Distribution  February 12, 2016 October 1, 2015 – December 31, 2015 $ 0.075 $ 3,868  $ 3,868   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 
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, 2016
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, 2016
DISCONTINUED OPERATIONS [Abstract]
Discontinued Operation Financial Information	Summarized financial information for our midstream segment was as follows:     2015 (1) 2014 (2)  Revenues $ 93,726 $ 237,344  Operating income 49,171 109,003  Net income 49,525 109,660 _____________ (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 39

Earnings Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2016
EARNINGS PER LIMITED PARTNER UNIT [Abstract]
Calculation of Earnings Per Limited Partner Unit	The following sets forth the calculation of earnings per limited partner unit for the years ended December 31:     2016 2015 2014  Income (loss) from continuing operations $ (242,895) $ (234,179) $ 22,245  General partner's 2% interest in income (loss) from  continuing operations 4,858 4,684 (445)  Earnings attributable to unvested phantom units - (1,076) (1,723)  Limited partners' interest in income (loss) from continuing  operations $ (238,037) $ (230,571) $ 20,077   Earnings per limited partner unit (basic and diluted) $ (4.85) $ (4.72) $ 0.41   Income (loss) from discontinued operations $ - $ 255,512 $ 107,475  General partner's 2% interest in income (loss) from  discontinued operations - (5,110) (2,150)  Earnings attributable to unvested phantom units - - -  Limited partners' interest in income (loss) from  discontinued operations $ - $ 250,402 $ 105,325   Earnings per limited partner unit (basic and diluted) $ - $ 5.13 $ 2.17   Net income (loss) $ (242,895) $ 21,333 $ 129,720  General partner's 2% interest in net income (loss) 4,858 (426) (2,595)  Earnings attributable to unvested phantom units - (1,076) (1,723)  Limited partners' interest in net income (loss) $ (238,037) $ 19,831 $ 125,402   Earnings per limited partner unit (basic and diluted) $ (4.85) $ 0.41 $ 2.58   Weighted average limited partner units outstanding  (basic and diluted) 49,048 48,853 48,563 

Other Supplemental Information

Other Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2016
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:     2016 2015 2014  Supplemental cash flows information:  Cash paid for interest, net of capitalized interest of $5,741  at December 31, 2014 $ 39,807 $ 48,344 $ 49,444  Cash (refunded) paid for income taxes 10,942 (115) 155   Non–cash transactions:  Costs for additions to oil and natural gas properties in accounts  payable and accrued liabilities 668 5,212 18,028  Post-closing adjustments for sales of oil and natural gas properties  in accounts payable and accrued liabilities 1,752 - - 
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued liabilities consisted of the following as of December 31:     2016 2015   Costs for additions to oil and natural gas properties $ 668 $ 5,212  Lease operating expenses 9,835 10,576  Interest 6,029 7,298  Production and ad valorem taxes 7,382 6,763  VPP - 3,984  General and administrative expenses 3,095 2,864  Current portion of ARO 3,235 2,930  Derivative settlements 106 -  Other 1,350 3,508  Total $ 31,700 $ 43,135 

Quarterly Data (Tables)

Quarterly Data (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Data [Abstract]
Schedule of Quarterly Data	    First Second Third Fourth  Quarter Quarter Quarter Quarter  2016  Revenues $ 38,250 $ 42,831 $ 51,372 $ 52,441  Gross profit (1) 7,328 14,776 23,240 27,296  Net (loss) income (2) (29,000) (28,993) (19,230) (165,672)  Net (loss) income per limited partner unit:  Basic $ (0.58) $ (0.58) $ (0.38) $ (3.31)  Diluted $ (0.58) $ (0.58) $ (0.38) $ (3.31)   2015  Revenues (3) $ 47,242 $ 44,456 $ 38,321 $ 47,952  Gross profit (1) 21,396 18,549 13,945 15,683  Net (loss) income (4) (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) _____________ (1) Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.  (2) Includes impairment charges of $131.3 million , primarily in the fourth quarter of 2016 . Of this amount, $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the expected present value of the future net cash flows. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale.  (3) Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4).  (4) Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015.

Supplementary Information On 42

Supplementary Information On Oil And Natural Gas Activities (Tables)	12 Months Ended
	Dec. 31, 2016
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:      2016 2015  Proved oil and natural gas properties $ 2,527,927 $ 2,694,354  Unproved oil and natural gas properties 20,884 67,600  2,548,811 2,761,954  Accumulated depreciation, depletion and amortization (1,051,600) (971,499)  Net capitalized costs $ 1,497,211 $ 1,790,455 
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:     2016 2015 2014  Acquisition of oil and natural gas properties:  Proved $ - $ 236,356 $ -  Unproved - 1,020 -  Exploration costs 651 2,193 2,585  Development costs 10,712 55,109 103,840  Total $ 11,363 $ 294,678 $ 106,425 

Estimated Proved Oil, Natural43

Estimated Proved Oil, Natural Gas And Natural Liquids Reserves (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2013 13,084 819,680 48,902 1,191,594  Revisions of previous estimates (4) (1,851) (138,666) (16,180) (246,856)  Purchases of minerals in place 21 1,515 222 2,974  Extensions and discoveries (5) 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 (6) (3,319) (194,442) (9,028) (268,522)  Purchases of minerals in place 11,852 214,578 7,468 330,504  Extensions and discoveries (7) 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  Revisions of previous estimates (8) (8,163) (57,723) (1,223) (114,041)  Extensions and discoveries (9) 61 10,255 736 15,038  Production (1,216) (49,333) (2,331) (70,612)  Sales of minerals in place (10) (85) (74,916) (81) (75,919)  As of December 31, 2016 12,592 575,298 33,395 851,219   Proved developed reserves:  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  December 31, 2016 11,954 523,113 28,218 764,149   Proved undeveloped reserves:  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  December 31, 2016 638 52,185 5,177 87,070 _____________ (1) Thousands of barrels.  (2) Million cubic feet.  (3) Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent .  (4) Revisions were primarily attributable to 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.  (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) 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.  (7) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 72.6 Bcfe) and the Appalachian Basin ( 16.9 Bcfe).  (8) Revisions were primarily attributable to reductions in the Appalachian Basin ( 51.8 Bcfe), the Barnett Shale ( 39.9 Bcfe) and Central Texas ( 13.5 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates from prices used in our December 31, 2015 reserve estimates.  (9) Extensions and discoveries were primarily associated with drilling success in the Barnett Shale ( 13.0 Bcfe).  (10) Sales of minerals in place were primarily associated with the sale of a portion of our Barnett Shale natural gas properties ( 74.2 Bcfe) in December 2016.

Standardized Measure Of Disco44

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, 2016
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:     2016 2015 2014  Future cash inflows $ 2,261,520 $ 3,285,271 $ 4,639,547  Future production and development costs (1,480,900) (2,029,001) (2,123,559)  Future income tax expenses (5,442) (7,769) (18,266)  Future net cash flows 775,178 1,248,501 2,497,722  10% annual discount for estimated timing of cash flows (404,061) (712,051) (1,404,419)  Standardized measure of discounted future net cash flows $ 371,117 $ 536,450 $ 1,093,303 
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:      2016 2015 2014  Standardized measure at beginning of period $ 536,450 $ 1,093,303 $ 1,039,785  Sales and transfers of oil, natural gas and natural gas liquids produced,  net of production costs (71,939) (68,479) (216,972)  Net changes in prices and production costs (83,146) (682,598) 131,899  Extensions, discoveries and improved recovery, less related costs 1,712 26,082 113,127  Development costs incurred during the period 2,065 21,441 23,737  Revisions and other (23,328) (205,821) (69,407)  Accretion of 10% timing discount 53,998 110,120 104,941  Changes in income taxes 1,093 4,362 1,725  Changes in estimated future development costs 3,976 19,925 (2,980)  Changes in timing and other (26,920) (31,118) (28,853)  Purchase of minerals in place - 250,646 4,376  Sales of minerals in place (22,844) (1,413) (8,075)  Standardized measure of discounted future net cash flows $ 371,117 $ 536,450 $ 1,093,303 

Organization and Nature of Bu45

Organization and Nature of Business (Narrative) (Details) - segment	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage of general partnership interest	2.00%
Number of reportable segments	1
EnerVest, Ltd.
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%
Percentage of general partnership interest	2.00%	2.00%	2.00%

Summary of Significant Accoun46

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2016USD ($)customer	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)customer	Oct. 31, 2015USD ($)
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts receivable	$ 0	$ 0
Doubtful accounts receivable, related expenses	0	0
Capitalized costs associated with unproved properties	20,900,000	67,600,000
Dry hole and exploration costs	651,000	3,695,000	$ 6,726,000
Impairment of oil and natural gas properties	131,260,000	$ 136,667,000	113,968,000
Concentration risk, number of clients | customer		2
Senior secured credit facility, maximum borrowing capacity	1,000,000,000
Goodwill				$ 65,924,000
Proved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	89,500,000	$ 86,900,000	103,300,000
Unproved Oil and Natural Gas Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	$ 41,800,000	$ 49,800,000	$ 10,700,000
Customer Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration risk, number of clients | customer			0
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member]
Significant Accounting Policies [Line Items]
Concentration risk, number of clients | customer	3
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | Major Customer One [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	18.50%	17.10%
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | Major Customer Two [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	13.40%	10.80%
Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | Major Customer Three [Member]
Significant Accounting Policies [Line Items]
Concentration risk, percentage	10.40%
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 Accoun47

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units and/or rights that may be awarded under long-term incentive plan		5,000,000
Units vested		214,807
Performance units issued to employees and executive officers		951,494
Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Units vested, fair value		$ 8.4	$ 15.2	$ 11.9
Compensation cost related to phantom or performance units recognized		6.6	$ 11.8	$ 13.9
Unrecognized compensation expense		$ 9.2
Weighted average period		2 years 4 months 24 days
Years used to calculate estimated volatility		2 years	2 years	2 years
Performance Units
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
Units vested, fair value			$ 1.6	$ 1.4
Compensation cost related to phantom or performance units recognized			$ 0.2	$ 5.4
Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant		4,000,000

Equity-Based Compensation (Acti

Equity-Based Compensation (Activity Related To Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Number of Units
Nonvested units as of December 31, 2015	1,689,248
Shares issued	951,494
Vested	(214,807)
Forfeited	(200,058)
Nonvested units as of December 31, 2016	2,225,877	1,689,248
Weighted Average Grant Date Fair Value per Phantom Unit
Nonvested units as of December 31, 2015	$ 13.39
Granted	2.05
Vested	39.29
Forfeited	10.49
Nonvested units as of December 31, 2016	6.31	$ 13.39
Equity Awards [Member]
Weighted Average Grant Date Fair Value per Phantom Unit
Granted	$ 2.05	$ 2.61	$ 22.77

Equity-Based Compensation (Assu

Equity-Based Compensation (Assumptions Used To Estimate Weighted Average Fair Value) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Weighted average fair value of phantom units	$ 2.05
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	$ 2.05	$ 2.61	$ 22.77
Expected volatility	83.41%	62.33%	34.52%
Risk-free interest rate	1.30%	1.13%	0.87%
Dividend yield	0.00%	0.00%	0.00%
Expected life (years)	4 years	4 years 1 month 6 days	4 years

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)	Jan. 31, 2017USD ($)	Oct. 31, 2015USD ($)MMcf
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price						$ 259,022
Oil, natural gas and natural gas liquids revenues		$ 182,696	$ 175,088	$ 334,729
Volume obligation to deliver, billion cubic feet (Bcf) of natural gas | MMcf	1,900		1,900			2,400
Liability related to volumetric production payment (VPP)	$ 3,984		$ 3,984
Goodwill						$ 65,924
Accretion expense		$ 100	$ 100
Subsequent Event [Member] | Affiliated Entity [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired interest, percentage					87.00%
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
Business acquisition, goodwill, expected tax deductible amount						$ 20,200
Eagle Ford Acquition [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired interest, percentage					5.80%
Oil and natural gas properties acquired, purchase price					$ 58,700
Eagle Ford Acquisition Paid with Divestiture Proceeds [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price					52,100
Eagle Ford Acquisition Paid with Credit Facility [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price					$ 6,600

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
Appalachian Basin, San Juan Basin, Michigan and Austin Chalk Properties [Member]
Business Acquisition [Line Items]
Pro forma revenues	$ 235,236	$ 488,422
Pro forma net income (loss)	(53,946)	158,701
Historical [Member]
Business Acquisition [Line Items]
Pro forma revenues	177,971	339,405
Pro forma net income (loss)	21,333	129,720
Belden [Member]
Business Acquisition [Line Items]
Pro forma revenues	24,292	65,453
Pro forma net income (loss)	(76,910)	(1,794)
Austin Chalk [Member]
Business Acquisition [Line Items]
Pro forma revenues	9,235	24,074
Pro forma net income (loss)	1,217	11,395
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Pro forma revenues	23,738	59,490
Pro forma net income (loss)	$ 414	$ 19,380

Acquisitions (Recognized Fair V

Acquisitions (Recognized Fair Values of Identifiable Assets Acquired and Liabilities Assumed) (Details) $ in Thousands	Oct. 31, 2015USD ($)
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, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net, Total	259,022
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, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net, Total	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, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net, Total	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, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net, Total	$ 122,021

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Dec. 31, 2016	Oct. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and natural gas properties			$ 54,509	$ 1,457	$ 45,183
Asset sold, impairment charges					200
Assets and liabilities sold, previously held for sale					5,800
Burleson, Brazos and Grimes Counties in Texas [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and natural gas properties					33,800
Cardinal Gas Services, LLC [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of equity method investments		$ 161,100
Barnett Shale [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and natural gas properties	$ 52,100
Other [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and natural gas properties			$ 2,400
Utica Shale
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and natural gas properties					$ 5,600

Risk Management (Schedule of Co

Risk Management (Schedule of Commodity Contracts) (Details)	Dec. 31, 2016MMBTU$ / MBbls$ / MMBTUMMBbls
Swaps - 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MmmBtus) | MMBTU	4,500
Weighted Average Fixed Price	3.46
Oil [Member] | Swaps - 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	365
Weighted Average Fixed Price | $ / MBbls	52.85
Natural Gas [Member] | Swaps - 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MmmBtus) | MMBTU	32,850
Weighted Average Fixed Price	3.07
Natural Gas [Member] | Collars - 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MmmBtus) | MMBTU	10,950
Weighted Average Floor Price	2.75
Weighted Average Ceiling Price	3.27
Natural Gas Liquids [Member] | Swaps - 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	766.50
Weighted Average Fixed Price | $ / MBbls	16.14

Risk Management (Interest Rate

Risk Management (Interest Rate Swaps) (Details) - 1-Month LIBOR [Member] $ in Thousands	Dec. 31, 2016USD ($)
Interest Rate Swaps 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 January 2018 - September 2020 [Member]
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, 2016	Dec. 31, 2015
Derivative Assets [Abstract]
Derivative asset, fair value	$ 201	$ 71,403
Derivative asset	201	60,662
Long-term derivative asset		10,741
Net recorded fair value	201	71,403
Derivative Liabilities [Abstract]
Derivative liability, fair value	22,634
Derivative liability	21,679
Long-term derivative liability	955
Net recorded fair value	22,634
Current Assets [Member]
Derivative Assets [Abstract]
Derivative asset, fair value	201	60,662
Derivative asset	201	60,662
Long-term Derivative Asset [Member]
Derivative Assets [Abstract]
Derivative asset, fair value		10,741
Long-term derivative asset		$ 10,741
Derivative Liability [Member]
Derivative Liabilities [Abstract]
Derivative liability, fair value	21,679
Derivative liability	21,679
Long-term Derivative Liability [Member]
Derivative Liabilities [Abstract]
Derivative liability, fair value	955
Long-term derivative liability	$ 955

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 131,260	$ 136,667	$ 113,968
Long-term Debt	606,948	688,614
Asset retirement obligation	183,476	176,933	105,773
Impairment losses		65,924
Goodwill				$ 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	242,600	211,900
Long-term Debt	$ 341,948	423,614
Nonrecurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment losses		65,924
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
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

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, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	$ 201	$ 71,403
Derivative liability, fair value	22,634
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
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
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]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	201
Derivative liability, fair value	22,634
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
Derivative liability, fair value	22,588
Recurring Basis [Member] | Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value	201	1,047
Derivative liability, fair value	46
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
Derivative liability, fair value
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Commodity Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value
Derivative liability, fair value
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative 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	201
Derivative liability, fair value	22,634
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
Derivative liability, fair value	22,588
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	201	1,047
Derivative liability, fair value	46
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
Derivative liability, fair value
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value
Derivative liability, fair value
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value
Derivative liability, fair value

Fair Value Measurements (Fair60

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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill, impairment loss	$ 65,924
Nonrecurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill, impairment loss	65,924
Long-lived assets	52,406	$ 88,844
Total losses	152,816	103,282
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
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
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
Total losses	86,892	103,118
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
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
Total losses		164
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

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
Asset retirement obligation, current	$ 3,235	$ 2,930

Asset Retirement Obligations (C

Asset Retirement Obligations (Changes in Aggregate Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
Balance at beginning of period	$ 176,933	$ 105,773
Liabilities incurred	1,223	70,005
Accretion expense	8,101	5,531
Revisions	820	1,344
Settlements and divestitures	(3,601)	(5,720)
Balance at end of period	$ 183,476	$ 176,933

Long-Term Debt, Net (Narrative)

Long-Term Debt, Net (Narrative) (Details) $ in Thousands	Mar. 22, 2011	Dec. 31, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity										$ 1,000,000
Senior credit facility, expiration date										Feb. 26, 2020
Senior secured debt to EBITDAX, ratio										3
EBITDAX to cash interest expense ratio									2.5
Weighted average effective interest rate										3.75%	3.73%
Line of credit, borrowing base										$ 450,000
Line of credit facility amount outstanding										265,000	$ 265,000
Letters of credit outstanding, amount										$ 300
Debt instrument, repurchased amount											50,000
Scenario, Plan [Member]
Debt Instrument [Line Items]
Senior secured debt to EBITDAX, ratio						4	3.5
Total debt to earnings ratio required under credit facility, revised		4.25	5.5		5.25
EBITDAX to cash interest expense ratio				1.5				2
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 credit facility, expiration date	Apr. 15, 2019
Senior unsecured notes, stated interest rate	8.00%
Redemption price if change of control occurs	101.00%
Senior notes, carrying amount										$ 343,348	426,022
Debt instrument, repurchased face amount										82,700	74,000
Debt instrument, repurchased amount										35,000
Gain (loss) on repurchase of debt instrument										47,700	$ 24,000
Debt instrument convenant, amount of cash										$ 30,000
Credit Facility [Member]
Debt Instrument [Line Items]
Debt instrument, covenant compliance, credit facility and letters of credit										we were in compliance with these financial covenants
Letter of Credit [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity										$ 100,000
Maximum amount of line of credit facility to be used for repurchase of debt										$ 35,000

Long-Term Debt, Net (Long Term

Long-Term Debt, Net (Long Term Debt) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Credit facility outstanding		$ 265,000	$ 265,000
Long-term debt, Total		606,948	688,614
8.0% Senior Notes due 2019 [Member]
Senior notes, outstanding		343,348	426,022
Unamortized discount and debt issuance costs	[1]	(2,946)	(5,116)
Unaccreted premium	[2]	1,546	2,708
Long-term debt, Total		$ 341,948	$ 423,614
Debt instrument, unamortized discount, imputed interest		8.99%	8.87%
Debt instrument, unaccreted expense, imputed interest		7.22%	7.35%
[1]	Imputed interest rate of 8.99% and 8.87% for 2016 and 2015, respectively.
[2]	Imputed interest rate of 7.22% and 7.35% for 2016 and 2015, respectively.

Long-Term Debt, Net (Redemption

Long-Term Debt, Net (Redemption Prices On Applicable Redemption Dates) (Details)	12 Months Ended
	Dec. 31, 2016
2017 [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	100.00%
2018 and Thereafter [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	100.00%

Commitments and Contingencies66

Commitments and Contingencies (Schedule of Future Minimum Transportation Fees Payment) (Details) $ in Thousands	Dec. 31, 2016USD ($)
COMMITMENTS AND CONTINGENCIES [Abstract]
2,017	$ 3,603
2,018	3,324
2,019	2,765
2,020	1,604
2,021	1,394
Thereafter	2,701
Balance as of December 31, 2016	$ 15,391

Owners' Equity (Narrative) (Det

Owners' Equity (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stockholders Equity Note [Line Items]
Percentage of limited partnership interest	98.00%
Percentage of general partnership interest	2.00%
Contribution from general partner		$ 91	$ 154
Period of distribution of available cash to unitholders after the end of each quarter	45 days
Distributions description	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; andthereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.
General partner affiliate ownership percentage for call	80.00%
General Partner Interest [Member]
Stockholders Equity Note [Line Items]
Partners capital distributions percentage of cash surplus	2.00%
Common Unitholders [Member]
Stockholders Equity Note [Line Items]
Partners capital distributions percentage of cash surplus	98.00%
Executive officers and directors
Stockholders Equity Note [Line Items]
Common unitholders, units outstanding	5,032,399
Common Unitholders [Member]
Stockholders Equity Note [Line Items]
Common unitholders, units issued	49,055,214	48,871,399
Common unitholders, units outstanding	49,055,214	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, 2016$ / shares
Minimum quarterly distribution
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
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 | Maximum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.875725
Second target distribution
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 | Maximum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.951875
Second target distribution | Minimum [Member]
Distribution Made to Limited Partner [Line Items]
Total quarterly distributions target amount	$ 0.875725
Thereafter
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 | 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Total Distribution	$ 3,868	$ 100,979	$ 154,978
Cash Distributions Period Covered October 1, 2015 - December 31, 2015
Distribution Made to Limited Partner [Line Items]
Date Paid	Feb. 12, 2016
Distribution per Unit	$ 0.075
Total Distribution	$ 3,868
Cash Distributions Period Covered October 1, 2014 - December 31, 2014
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
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
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
Distribution Made to Limited Partner [Line Items]
Date Paid		Nov. 13, 2015
Distribution per Unit		$ 0.500
Total Distribution		$ 25,241

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	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	$ (245,270)	(236,022)	$ 22,721
Loss subject to taxation		45,700
Income tax expense (benefit)	$ (2,375)	(1,843)	$ 476
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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ (2,375)	$ (1,843)	$ 476

Income Taxes (Schedule of Effec

Income Taxes (Schedule of Effective Income Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ (2,375)	$ (1,843)	$ 476

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Acquisitions And Disposals [Line Items]
Proceeds from sale of oil and natural gas properties				$ 54,509	$ 1,457	$ 45,183
Payment on lines of credit				$ 57,000	$ 561,000	$ 159,000
Utica East Ohio Midstream LLC
Significant Acquisitions And Disposals [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]
Significant Acquisitions And Disposals [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	[2]
DISCONTINUED OPERATIONS [Abstract]
Revenues	$ 93,726		$ 237,344
Operating income	49,171		109,003
Net income	$ 49,525		$ 109,660
[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 75

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share Disclosure [Line Items]
(Loss) income from continuing operations																	$ (242,895)	$ (234,179)	$ 22,245
General partner's 2% interest in (loss) income from continuing operations																	4,858	4,684	(445)
Earnings attributable to unvested phantom units, continuing operations																		(1,076)	(1,723)
Limited partners' interest in (loss) income from continuing operations																	$ (238,037)	$ (230,571)	$ 20,077
Earnings per limited partner unit basic, continued																	$ (4.85)	$ (4.72)	$ 0.41
Earnings per limited partner unit diluted, continued																	$ (4.85)	$ (4.72)	$ 0.41
Income from discontinued operations																		$ 255,512	$ 107,475
General partner's 2% interest in income (loss) from discontinued operations																		(5,110)	(2,150)
Limited partners' interest in income (loss) from discontinued operations																		$ 250,402	$ 105,325
Earnings per limited partner unit basic, discontinued																		$ 5.13	$ 2.17
Earnings per limited partner unit diluted, discontinued																		$ 5.13	$ 2.17
Net income (loss)	$ (165,672)	[1]	$ (19,230)	[1]	$ (28,993)	[1]	$ (29,000)	[1]	$ (71,264)	[2]	$ (9,838)	[2]	$ 164,102	[2]	$ (61,667)	[2]	$ (242,895)	$ 21,333	$ 129,720
General partner's 2% interest in net income (loss)																	4,858	(426)	(2,595)
Earnings attributable to unvested phantom units																		(1,076)	(1,723)
Limited partners' interest in net income (loss)																	$ (238,037)	$ 19,831	$ 125,402
Earnings per limited partner unit basic	$ (3.31)		$ (0.38)		$ (0.58)		$ (0.58)		$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ (4.85)	$ 0.41	$ 2.58
Earnings per limited partner unit diluted	(3.31)		(0.38)		(0.58)		(0.58)		(1.43)		(0.20)		3.25		(1.25)		$ (4.85)	$ 0.41	$ 2.58
Percentage of general partnership interest																	2.00%
Weighted average limited partner units outstanding:
Denominator for basic net loss per limited partner unit - common units																	49,048,000	48,853,000	48,563,000
Weighted average limited partner units outstanding, basic																	49,048,000	48,853,000	48,563,000
Weighted average limited partner units outstanding, diluted																	49,048,000	48,853,000	48,563,000
Earnings per limited partner unit (basic and diluted):
Basic	(3.31)		(0.38)		(0.58)		(0.58)		(1.43)		(0.20)		3.25		(1.25)		$ (4.85)	$ 0.41	$ 2.58
Diluted	$ (3.31)		$ (0.38)		$ (0.58)		$ (0.58)		$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)		$ (4.85)	$ 0.41	$ 2.58
Equity awards not included in computation of diluted net income (loss) per limited partner unit																	0	0
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																			200,000
[1]	Includes impairment charges of $131.3 million, primarily in the fourth quarter of 2016. Of this amount, $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the expected present value of the future net cash flows. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale.
[2]	Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015.

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2011	Oct. 31, 2015
Related Party Transaction [Line Items]
Related party, receivable	$ 745
Related party	5,797	$ 5,952
Business Acquisition Purchase Price Allocation Assets Acquired Liabilities Assumed Net					$ 259,022
EnerVest, Ltd.
Related Party Transaction [Line Items]
Administrative fees paid to related party	15,900	14,200	$ 12,100
Direct expenses incurred and reimbursed to related party	21,200	17,200	17,000
Overriding royalty interests
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	100	200	400
Dividends from unconsolidated affiliates	$ 100	$ 200	$ 300

Other Supplemental Informatio77

Other Supplemental Information (Supplemental Cash Flows and Non-Cash Transactions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental cash flows information:
Cash paid for interest	$ 39,807	$ 48,344	$ 49,444
Cash (refunded) paid for income taxes	10,942	(115)	155
Capitalized interest			5,741
Non-cash transactions:
Noncash transaction - costs for additions to oil and natural gas properties in accounts payable and accrued liabilities	668	$ 5,212	$ 18,028
Noncash transaction - post-closing adjustments for sales of oil and natural gas properties in accounts payable and accrued liabilities	$ 1,752

Other Supplemental Informatio78

Other Supplemental Information (Schedule of Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
OTHER SUPPLEMENTAL INFORMATION [Abstract]
Costs for additions to oil and natural gas properties	$ 668	$ 5,212
Lease operating expenses	9,835	10,576
Interest	6,029	7,298
Production and ad valorem taxes	7,382	6,763
VPP		3,984
General and administrative expenses	3,095	2,864
Current portion of ARO	3,235	2,930
Derivative settlements	106
Other	1,350	3,508
Total	$ 31,700	$ 43,135

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, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues			$ 52,441		$ 51,372		$ 42,831		$ 38,250		$ 47,952	[1]	$ 38,321	[1]	$ 44,456	[1]	$ 47,242	[1]		$ 184,894	$ 177,971	$ 339,405
Gross profit	[2]		27,296		23,240		14,776		7,328		15,683		13,945		18,549		21,396
Net (loss) income			$ (165,672)	[3]	$ (19,230)	[3]	$ (28,993)	[3]	$ (29,000)	[3]	$ (71,264)	[4]	$ (9,838)	[4]	$ 164,102	[4]	$ (61,667)	[4]		(242,895)	21,333	129,720
Limited partners' interest in net loss																				$ (238,037)	$ 19,831	$ 125,402
Earnings per limited partner unit (basic and diluted):
Basic			$ (3.31)		$ (0.38)		$ (0.58)		$ (0.58)		$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)			$ (4.85)	$ 0.41	$ 2.58
Diluted			$ (3.31)		$ (0.38)		$ (0.58)		$ (0.58)		$ (1.43)		$ (0.20)		$ 3.25		$ (1.25)			$ (4.85)	$ 0.41	$ 2.58
Impairment of oil and gas properties																				$ 131,260	$ 136,667	$ 113,968
Impairment of leasehold																				41,800
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
Appalachian Basin [Member]
Earnings per limited partner unit (basic and diluted):
Impairment of leasehold																				35,800
Proved Oil and Natural Gas Properties [Member]
Earnings per limited partner unit (basic and diluted):
Impairment of oil and gas properties																				89,500	$ 86,900	$ 103,300
Proved Oil and Natural Gas Properties [Member] | Barnett Shale [Member]
Earnings per limited partner unit (basic and diluted):
Impairment of oil and gas properties																				$ 89,500
[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 impairment charges of $131.3 million, primarily in the fourth quarter of 2016. Of this amount, $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the expected present value of the future net cash flows. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale.
[4]	Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015.

Supplementary Information on 80

Supplementary Information on Oil and Natural Gas Activities (Capitalized Costs Relating to Oil and Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Supplementary Information On Oil And Natural Gas Activities [Abstract]
Proved oil and natural gas properties	$ 2,527,927	$ 2,694,354
Unproved oil and natural gas properties	20,884	67,600
Total oil and natural gas properties	2,548,811	2,761,954
Accumulated depreciation, depletion and amortization	(1,051,600)	(971,499)
Oil and Gas Property, Successful Effort Method, Net, Total	$ 1,497,211	$ 1,790,455

Supplementary Information on 81

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Acquisition of oil and natural gas properties:
Proved		$ 236,356
Unproved		1,020
Exploration costs	$ 651	2,193	$ 2,585
Development costs	10,712	55,109	103,840
Total	$ 11,363	$ 294,678	$ 106,425

Estimated Proved Oil, Natural82

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, 2016McfeMMBblsMMcf		Dec. 31, 2015McfeMMBblsMMcf		Dec. 31, 2014McfeMMBblsMMcf		Dec. 31, 2013McfeMMBblsMMcf
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance, energy | Mcfe	[1]	1,096,753		1,000,496		1,191,594
Revisions of previous estimates, energy | Mcfe	[1]	(114,041)	[2]	(268,522)	[3]	(246,856)	[4]
Purchase of minerals in place, energy | Mcfe	[1]			330,504		2,974
Extensions and discoveries, energy | Mcfe	[1]	15,038	[5]	100,647	[6]	127,571	[7]
Production, energy | Mcfe	[1]	(70,612)		(63,792)		(63,540)
Sales of minerals in place, energy | Mcfe	[1]	(75,919)	[8]	(2,580)		(11,247)
Proved developed and undeveloped reserves, ending balance, energy | Mcfe	[1]	851,219		1,096,753		1,000,496		1,191,594
Proved developed reserves (energy) | Mcfe	[1]	764,149		909,047		842,956		815,268
Proved undeveloped reserves (energy) | Mcfe	[1]	87,070		187,706		157,540		376,326
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	[9]	21,995,000		11,908,000		13,084,000
Revisions of previous estimates	[9]	(8,163,000)	[2]	(3,319,000)	[3]	(1,851,000)	[4]
Purchases of minerals in place	[9]			11,852,000		21,000
Extensions and discoveries	[9]	61,000	[5]	2,636,000	[6]	1,900,000	[7]
Production	[9]	(1,216,000)		(1,041,000)		(1,052,000)
Sales of minerals in place	[9]	(85,000)	[8]	(41,000)		(194,000)
Proved developed and undeveloped reserves, ending balance	[9]	12,592,000		21,995,000		11,908,000		13,084,000
Proved developed reserves (volume)	[9]	11,954,000		13,919,000		9,783,000		10,443,000
Proved undeveloped reserve (volume)	[9]	638,000		8,076,000		2,125,000		2,641,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | MMcf	[10]	747,015		712,192		819,680
Revisions of previous estimates | MMcf	[10]	(57,723)	[2]	(194,442)	[3]	(138,666)	[4]
Purchases of minerals in place | MMcf	[10]			214,578		1,515
Extensions and discoveries | MMcf	[10]	10,255	[5]	60,197	[6]	81,571	[7]
Production | MMcf	[10]	(49,333)		(43,592)		(43,363)
Sales of minerals in place | MMcf	[10]	(74,916)	[8]	(1,918)		(8,545)
Proved developed and undeveloped reserves, ending balance | MMcf	[10]	575,298		747,015		712,192		819,680
Proved developed reserves (volume) | MMcf	[10]	523,113		644,984		599,664		578,274
Proved undeveloped reserve (volume) | MMcf	[10]	52,185		102,031		112,528		241,406
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	[9]	36,294,000		36,143,000		48,902,000
Revisions of previous estimates	[9]	(1,223,000)	[2]	(9,028,000)	[3]	(16,180,000)	[4]
Purchases of minerals in place	[9]			7,468,000		222,000
Extensions and discoveries	[9]	736,000	[5]	4,106,000	[6]	5,767,000	[7]
Production	[9]	(2,331,000)		(2,326,000)		(2,311,000)
Sales of minerals in place	[9]	(81,000)	[8]	(69,000)		(257,000)
Proved developed and undeveloped reserves, ending balance	[9]	33,395,000		36,294,000		36,143,000		48,902,000
Proved developed reserves (volume)	[9]	28,218,000		30,091,000		30,766,000		29,056,000
Proved undeveloped reserve (volume)	[9]	5,177,000		6,203,000		5,377,000		19,846,000
Barnett Shale [Member]
Reserve Quantities [Line Items]
Sales of minerals in place, energy | Mcfe		74,200
Volume produced from oil drilling success | Mcfe		13,000		72,600		78,200
Barnett Shale [Member] | Reduction [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves | Mcfe		39,900		120,700
Appalachian Basin [Member]
Reserve Quantities [Line Items]
Volume produced from oil drilling success | Mcfe		16,900				33,000
Appalachian Basin [Member] | Reduction [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves | Mcfe		51,800		76,900
Central Texas [Member] | Reduction [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves | Mcfe		13,500
[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 reductions in the Appalachian Basin (51.8 Bcfe), the Barnett Shale (39.9 Bcfe) and Central Texas (13.5 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates from prices used in our December 31, 2015 reserve estimates.
[3]	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.
[4]	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.
[5]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (13.0 Bcfe).
[6]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (72.6 Bcfe) and the Appalachian Basin (16.9 Bcfe).
[7]	Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 Bcfe).
[8]	Sales of minerals in place were primarily associated with the sale of a portion of our Barnett Shale natural gas properties (74.2 Bcfe) in December 2016.
[9]	Thousands of barrels.
[10]	Million cubic feet.

Standardized Measure of Disco83

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, 2016$ / MMBTU$ / item	Dec. 31, 2015$ / MMBTU$ / item	Dec. 31, 2014$ / 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	42.75	50.28	94.99
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	2.481	2.587	4.350

Standardized Measure of Disco84

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, 2016	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]
Future cash inflows	$ 2,261,520,000	$ 3,285,271,000	$ 4,639,547,000
Future production and development costs	(1,480,900,000)	(2,029,001,000)	(2,123,559,000)
Future income tax expenses	(5,442,000)	(7,769,000)	(18,266,000)
Future net cash flows	775,178,000	1,248,501,000	2,497,722,000
10% annual discount for estimated timing of cash flows	(404,061,000)	(712,051,000)	(1,404,419,000)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 371,117,000	$ 536,450,000	$ 1,093,303,000	$ 1,039,785,000
Future net cash flows, annual discount rate	10.00%	10.00%	10.00%

Standardized Measure of Disco85

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Standardized Measure of Discontinued Future Net Cash Flows Relating to Proved Oil, Natural Gas and Natural Gas Liquids Reserves [Abstract]
Standardized measure at beginning of period	$ 536,450,000	$ 1,093,303,000	$ 1,039,785,000
Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	(71,939,000)	(68,479,000)	(216,972,000)
Net changes in prices and production costs	(83,146,000)	(682,598,000)	131,899,000
Extensions, discoveries and improved recovery, less related costs	1,712,000	26,082,000	113,127,000
Development costs incurred during the period	2,065,000	21,441,000	23,737,000
Revisions and other	(23,328,000)	(205,821,000)	(69,407,000)
Accretion of 10% timing discount	53,998,000	110,120,000	104,941,000
Changes in income taxes	1,093,000	4,362,000	1,725,000
Changes in estimated future development costs	3,976,000	19,925,000	(2,980,000)
Changes in timing and other	(26,920,000)	(31,118,000)	(28,853,000)
Purchase of minerals in place		250,646,000	4,376,000
Sales of minerals in place	(22,844,000)	(1,413,000)	(8,075,000)
Standardized measure of discounted future net cash flows	$ 371,117,000	$ 536,450,000	$ 1,093,303,000
Accretion timing discount rate	10.00%	10.00%	10.00%