Black Stone Minerals (BSM) 10-Q 13 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 07, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	BSM
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Central Index Key	1,621,434
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Common Units
Document Information [Line Items]
Entity Partnership Units Outstanding		96,185,592
Subordinate Units
Document Information [Line Items]
Entity Partnership Units Outstanding		95,057,312
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding		117,963

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 6,048	$ 14,803
Accounts receivable	54,215	74,092
Commodity derivative assets	8,294	37,471
Prepaid expenses and other current assets	1,863	8,538
TOTAL CURRENT ASSETS	70,420	134,904
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, on the basis of the successful efforts method of accounting, includes unproved properties of $574,727 and $626,376 at June 30, 2015 and December 31, 2014, respectively	2,427,965	2,379,543
Accumulated depreciation, depletion and amortization, including impairment	(1,382,428)	(1,191,861)
Oil and natural gas properties, net	1,045,537	1,187,682
Other property and equipment, net of accumulated depreciation of $14,124 and $12,994 at June 30, 2015 and December 31, 2014, respectively	562	1,664
NET PROPERTY AND EQUIPMENT	1,046,099	1,189,346
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	2,050	2,532
TOTAL ASSETS	1,118,569	1,326,782
CURRENT LIABILITIES
Accounts payable	35,332	29,415
Accrued liabilities	15,233	16,252
Commodity derivative liabilities	1,108
TOTAL CURRENT LIABILITIES	65,497	98,572
LONG-TERM LIABILITIES
Credit facility	6,000	394,000
Accrued incentive compensation	6,247	6,530
Commodity derivative liabilities	2,850
Deferred revenue	3,427	3,917
Asset retirement obligations	9,908	9,381
TOTAL LIABILITIES	$ 93,929	$ 512,400
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners' equity - redeemable preferred units, 118 and 157 units outstanding at June 30, 2015 and December 31, 2014, respectively	$ 120,904	$ 161,165
EQUITY
Noncontrolling interests	2,351
TOTAL EQUITY	903,736	653,217
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	1,118,569	1,326,782
Predecessor
CURRENT LIABILITIES
Accrued distribution payable to Predecessor unitholders	13,824	52,905
EQUITY
TOTAL EQUITY		653,217
Common Units
EQUITY
Partners' equity - limited partner units	607,210
Common Units | Predecessor
EQUITY
Partners' equity - limited partner units		$ 653,217
Subordinate Units
EQUITY
Partners' equity - limited partner units	$ 294,175

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Oil and natural gas properties, unproved property costs	$ 574,727	$ 626,376
Other property and equipment accumulated depreciation and amortization	$ 14,124	$ 12,994
Preferred Units
Partners' equity, preferred units, outstanding	117,963	157,203
Common Units
Partners' equity, limited partner units, outstanding	96,186,000	0
Common Units | Predecessor
Partners' equity, limited partner units, outstanding	0	164,484,000
Subordinate Units
Partners' equity, limited partner units, outstanding	95,057,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUE
Oil and condensate sales	$ 46,293	$ 64,934	$ 82,456	$ 124,576
Natural gas and natural gas liquids sales	28,968	52,434	60,608	110,640
Gain (loss) on commodity derivative instruments	(18,627)	(2,348)	1,020	(8,343)
Lease bonus and other income	8,169	3,917	11,780	19,476
TOTAL REVENUE	64,803	118,937	155,864	246,349
OPERATING (INCOME) EXPENSE
Lease operating expenses and other	5,641	4,805	11,813	9,674
Production costs and ad valorem taxes	9,819	10,822	18,075	21,408
Depreciation, depletion and amortization	32,235	23,859	60,126	46,993
Impairment of oil and natural gas properties	118,362		131,829
General and administrative	19,718	14,512	34,536	29,963
Accretion of asset retirement obligations	269	148	540	295
Gain on sale of assets	(17)		(24)
TOTAL OPERATING EXPENSE	186,027	54,146	256,895	108,333
INCOME (LOSS) FROM OPERATIONS	(121,224)	64,791	(101,031)	138,016
OTHER INCOME (EXPENSE)
Interest and investment income	27	2	28	24
Interest expense	(1,715)	(3,419)	(4,660)	(6,852)
Other income	146	737	196	807
TOTAL OTHER EXPENSE	(1,542)	(2,680)	(4,436)	(6,021)
NET INCOME (LOSS)	(122,766)	62,111	(105,467)	131,995
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING	140		140
DIVIDENDS ON PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(1,810)		(1,810)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND LIMITED PARTNERS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(107,587)		(107,587)
ALLOCATION OF NET LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND LIMITED PARTNERS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(107,587)		(107,587)
Predecessor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	(16,849)	$ 62,111	450	$ 131,995
Common Units
ALLOCATION OF NET LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Limited partner interests	$ (54,109)		$ (54,109)
NET LOSS ATTRIBUTABLE TO LIMITED PARTNERS PER UNIT:
Per limited partner unit (basic)	$ (0.56)		$ (0.56)
Per limited partner unit (diluted)	$ (0.56)		$ (0.56)
Weighted average limited partner units outstanding (basic and diluted)	96,178		96,178
Subordinate Units
ALLOCATION OF NET LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Limited partner interests	$ (53,478)		$ (53,478)
NET LOSS ATTRIBUTABLE TO LIMITED PARTNERS PER UNIT:
Per limited partner unit (basic)	$ (0.56)		$ (0.56)
Per limited partner unit (diluted)	$ (0.56)		$ (0.56)
Weighted average limited partner units outstanding (basic and diluted)	95,057		95,057

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) shares in Thousands, $ in Thousands	Total	Common Units	Subordinate Units	Partners Equity Common Units	Partners Equity Subordinated Units	Noncontrolling Interest
Beginning balance (Predecessor) at Dec. 31, 2014	$ 653,217
Beginning balance at Dec. 31, 2014	653,217
Beginning balance, units (Predecessor) at Dec. 31, 2014		164,484
Conversion of Predecessor redeemable preferred units | Predecessor	39,240
Conversion of Predecessor redeemable preferred units	39,240
Conversion of Predecessor preferred units, units | Predecessor		2,750
Restricted common units granted | Predecessor		562
Restricted common units granted		1,111
Repurchases of Predecessor units | Predecessor	(3,015)
Repurchases of Predecessor units	(3,015)
Repurchases of Predecessor units, units | Predecessor		(164)
Distributions to Predecessor unitholders and noncontrolling interests | Predecessor	(73,205)
Distributions to Predecessor unitholders and noncontrolling interests	(73,205)
Dividends on Predecessor preferred units | Predecessor	(4,040)
Dividends on Predecessor preferred units	(4,040)
Allocation of Predecessor units and partners' equity to common and subordinated units | Predecessor	(612,647)
Allocation of Predecessor units and partners' equity to common and subordinated units				$ 264,235	$ 345,875	$ 2,537
Allocation of Predecessor units and partners' equity to common and subordinated units, units | Predecessor		(167,632)
Allocation of Predecessor units and partners' equity to common and subordinated units, units		72,575	95,057
Issuance of common units for initial public offering, net of offering costs	391,500			391,500
Issuance of common units for initial public offering, net of offering costs, units		22,500
Equity-based compensation	7,362			5,584	1,778
Distributions to noncontrolling interests	(46)					(46)
Net income (loss) | Predecessor	450
Net income (loss)	(105,467)			(53,199)	(52,578)	(140)
Dividends on preferred units	(1,810)			(910)	(900)
Ending balance at Jun. 30, 2015	$ 903,736			$ 607,210	$ 294,175	$ 2,351
Ending balance, units at Jun. 30, 2015		96,186	95,057

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (105,467)	$ 131,995
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	60,126	46,993
Impairment of oil and natural gas properties	131,829
Accretion of asset retirement obligations	540	295
Amortization of deferred charges	482	483
(Gain) loss on commodity derivative instruments	(1,020)	8,343
Net cash received (paid) on settlement of commodity derivative instruments	34,155	(2,943)
Equity-based compensation	7,362	5,654
Gain on disposal of assets	(24)
Changes in operating assets and liabilities:
Accounts receivable	19,881	(14,282)
Prepaid expenses and other current assets	(912)	(6,246)
Accounts payable and accrued liabilities	(2,273)	(1,904)
Deferred revenue	(490)	(2,516)
Settlement of asset retirement obligations	(105)	(12)
NET CASH PROVIDED BY OPERATING ACTIVITIES	144,084	165,860
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties	(32,819)	(40,454)
Purchase of other property and equipment	(28)	(226)
Proceeds from the sale of oil and natural gas properties	406	10,256
Acquisitions of oil and natural gas properties	(9,574)	(29,431)
NET CASH USED IN INVESTING ACTIVITIES	(42,015)	(59,855)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs	399,394
Distributions to noncontrolling interests	(122)	(168)
Repurchase of common equity units	(3,015)	(5,199)
Dividends on preferred units	(6,871)	(7,850)
Net (repayments) borrowings under senior line of credit	(388,000)	2,000
Note receivable-officers		101
NET CASH USED IN FINANCING ACTIVITIES	(110,824)	(123,339)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(8,755)	(17,334)
CASH AND CASH EQUIVALENTS - beginning of the period	14,803	30,123
CASH AND CASH EQUIVALENTS - end of the period	6,048	12,789
SUPPLEMENTAL DISCLOSURE
Interest paid	4,192	6,480
NON-CASH ACTIVITIES
Conversion of redeemable preferred units	(39,240)	(221)
Accrued distributions payable for preferred units	(1,021)	(49)
Property additions and acquisitions financed through accounts payable and accrued liabilities	20,713	22,784
Accrued public offering costs and prior period costs incurred	7,894
Asset retirement obligations incurred	92	62
Liabilities assumed as consideration for oil and natural gas properties acquired		7,000
Acquisition of oil and natural gas properties financed through issuance of common units		2,258
Deferred revenue settled through acquisition of oil and natural gas properties		(2,657)
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	450	131,995
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to Predecessor unitholders	(112,210)	(112,223)
NON-CASH ACTIVITIES
Accrued Predecessor distributions payable	$ (39,081)	$ 236

Business and Basis of Presentat

Business and Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Business and Basis of Presentation	NOTE 1—BUSINESS AND BASIS OF PRESENTATION Description of the business Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States. In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 preferred units of BSM at a conversion ratio of one to one. The merger is accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Company” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries. In addition to mineral interests, the Company’s assets include nonparticipating and overriding royalty interests. These non-cost-bearing interests are collectively referred to as “mineral and royalty interests.” As of June 30, 2015, the Company’s mineral and royalty interests are located in most of the major onshore oil and natural gas producing basins spread across 41 states and 62 onshore oil and natural gas producing basins of the continental U.S. The Company also owns non-operated working interests in certain oil and natural gas properties. Basis of presentation Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Company. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for a fair presentation of the results for the periods presented have been reflected. The results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of the results to be expected for the full year. The Company evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Company has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Company’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Company exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Company, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Company accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. Segment reporting

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant accounting policies: New accounting pronouncements Revenue Recognition In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance will be material to the Company’s consolidated financial statements and related disclosures. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. The Company does not expect the impact of adopting this guidance will be material to the Company’s consolidated financial statements and related disclosures.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	NOTE 3—ASSET RETIREMENT OBLIGATIONS The asset retirement obligation (“ARO”) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and natural gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of its properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Company’s ARO liability during the period: For the six months ended June 30, 2015 (In thousands) Beginning asset retirement obligations $ 9,381 Liabilities incurred 92 Liabilities settled (105 ) Accretion expense 540 Ending asset retirement obligations $ 9,908

Derivatives and Financial Instr

Derivatives and Financial Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivatives and Financial Instruments	NOTE 4—DERIVATIVES AND FINANCIAL INSTRUMENTS The Company’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate these price fluctuations, the Company uses commodity derivative instruments. From time to time, such instruments may include fixed-price contracts, variable-to-fixed-price swaps, costless collars, and other contractual arrangements. The Company does not enter into derivative instruments for speculative purposes. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. With a costless collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the exercise price of the purchased put. The Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the exercise price for the sold call of the collar. The settlement paid or received is the difference between the market price on the settlement date and the related exercise price. The Company has also entered into commodity derivative instruments in the form of fixed price swap contracts. A fixed-price-swap contract between the Company and the counterparty specifies a fixed commodity price and a future settlement date. The Company will receive from, or pay to, the counterparty the difference between the fixed swap price and the market price on the settlement date. All derivative instruments that have not yet been settled in cash are reflected as either assets or liabilities in the Company’s accompanying consolidated balance sheets as of June 30, 2015 and December 31, 2014. See Note 5 – Fair Value Measurement for further discussion. The table below summarizes the fair value and classification of the Company’s derivative instruments: As of June 30, 2015 (In thousands) Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet Assets: Current asset Commodity derivative assets $ 11,385 $ (3,091 ) $ 8,294 Long-term asset Deferred charges and other long-term assets 109 (109 ) — Total assets $ 11,494 $ (3,200 ) $ 8,294 Liabilities: Current liability Commodity $ 4,199 $ (3,091 ) $ 1,108 Long-term liability Commodity derivative liabilities 2,959 (109 ) 2,850 Total liabilities $ 7,158 $ (3,200 ) $ 3,958 As of December 31, 2014 (In thousands) Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet Assets: Current asset Commodity derivative assets $ 37,656 $ (185 ) $ 37,471 Long-term asset Deferred charges and other long-term assets — — — Total assets $ 37,656 $ (185 ) $ 37,471 Liabilities: Current liability Commodity derivative liabilities $ 185 $ (185 ) $ — Long-term liability Commodity derivative liabilities — — — Total liabilities $ 185 $ (185 ) $ — Changes in the fair values of the Company’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations. Changes in the fair value of the Company’s commodity derivative instruments (both assets and liabilities) are as follows: For the six months ended June 30, Derivatives not designated as hedging instruments under ASC 815 2015 2014 (In thousands) Beginning fair value of commodity derivative instruments $ 37,471 $ (1,812 ) Loss on oil derivative instruments (3,696 ) (6,456 ) Gain (loss) on natural gas derivative instruments 4,716 (1,887 ) Net cash (received) paid on settlements of oil derivative instruments (22,413 ) 273 Net cash (received) paid on settlements of natural gas derivative instruments (11,742 ) 2,670 Net change in fair value of commodity derivative instruments (33,135 ) (5,400 ) Ending fair value of commodity derivative instruments $ 4,336 $ (7,212 ) The Company had the following open derivative contracts for oil as of June 30, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Collars: Q2 2015 Collar contracts: Call Options 92,000 $ 102.73 $ 101.00 $ 104.00 Put Options 92,000 $ 86.14 $ 84.00 $ 90.00 Q3 2015 Collar contracts: Call Options 161,000 $ 102.45 $ 102.00 $ 103.55 Put Options 161,000 $ 84.88 $ 84.00 $ 87.00 Q4 2015 Collar contracts: Call Options 30,000 $ 102.00 $ 102.00 $ 102.00 Put Options 30,000 $ 85.00 $ 85.00 $ 85.00 Oil Swaps: Q2 2015 Swap contracts: 108,000 $ 57.69 $ 55.60 $ 58.77 Q3 2015 Swap contracts: 405,000 $ 58.99 $ 56.76 $ 60.22 Q4 2015 Swap contracts: 471,000 $ 60.60 $ 59.00 $ 61.71 2016 Swap contracts: 1,638,000 $ 58.21 $ 54.80 $ 63.07 2017 Swap contracts: 343,000 $ 63.28 $ 62.87 $ 63.65 The Company had the following open derivative contracts for natural gas as of June 30, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swaps: Q3 2015 Swap contracts: 7,590,000 $ 3.09 $ 2.84 $ 3.22 Q4 2015 Swap contracts: 6,900,000 $ 3.25 $ 2.88 $ 3.53 2016 Swap contracts: 22,940,000 $ 3.18 $ 3.03 $ 3.41 2017 Swap contracts: 4,640,000 $ 3.49 $ 3.43 $ 3.52 The Company entered into the following derivative contracts for oil subsequent to June 30, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swaps: Q3 2015 Swap contracts: 20,000 $ 46.88 $ 46.86 $ 46.90 Q4 2015 Swap contracts: 60,000 $ 48.13 $ 47.39 $ 49.18 2016 Swap contracts: 141,000 $ 50.95 $ 48.54 $ 53.30 2017 Swap contracts: 360,000 $ 53.95 $ 52.73 $ 54.38 The Company entered into the following derivative contracts for natural gas subsequent to June 30, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swaps: Q3 2015 Swap contracts: 280,000 $ 2.80 $ 2.80 $ 2.80 Q4 2015 Swap contracts: 700,000 $ 2.94 $ 2.82 $ 3.11 2016 Swap contracts: 1,310,000 $ 3.12 $ 3.00 $ 3.35 2017 Swap contracts: 5,010,000 $ 3.18 $ 3.14 $ 3.46

Fair Value Measurement

Fair Value Measurement	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	NOTE 5—FAIR VALUE MEASUREMENT ASC 820, Fair Value Measurement, ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 —Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 —Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 —Inputs that are unobservable and significant to the fair value measurement (including the Company’s own assumptions in determining fair value). A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the six months ended June 30, 2015 or the year ended December 31, 2014. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 4 – Derivatives and Financial Instruments for further discussion. The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Level 1 Level 2 Level 3 Netting Total (In thousands) As of June 30, 2015 Financial Assets Commodity derivative instruments $ — $ 11,494 $ — $ (3,200 ) $ 8,294 Financial Liabilities Commodity derivative instruments — 7,158 — (3,200 ) $ 3,958 As of December 31, 2014 Financial Assets Commodity derivative instruments $ — $ 37,656 $ — $ (185 ) $ 37,471 Financial Liabilities Commodity derivative instruments — 185 — (185 ) $ — Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The determination of the fair values of proved and unproved properties acquired in purchase transactions are prepared by estimating discounted-cash-flow projections. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a market-based weighted-average cost of capital. Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. Significant Level 3 assumptions used to determine fair value include estimates of proved reserves, future commodity prices, the timing and amount of future production and capital expenditures, and a discount rate commensurate with the risk associated with the respective oil and natural gas properties. The Company’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of June 30, 2015 or December 31, 2014. The following table presents information about the Company’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value Impairment (In thousands) As of June 30, 2015 Impaired oil and natural gas properties $ — $ — $ 89,671 $ 221,500 $ 131,829 As of December 31, 2014 Impaired oil and natural gas properties $ — $ — $ 81,864 $ 199,794 $ 117,930 The estimated fair value of all debt as of June 30, 2015 and December 31, 2014 approximated the carrying value. These fair values, which are Level 3 measurements, were estimated based on the Company’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Company’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 6—RELATED PARTY TRANSACTIONS The Predecessor executed promissory notes dated April 15, 2010, in the amount of $0.5 million to certain officers of the Predecessor. The promissory notes related to the acquisition of a partnership interest in a former affiliate by the officers, and the notes were collateralized by a security interest in the Predecessor. The aggregate outstanding note balance and interest receivable of $0.1 million was received during the six months ended June 30, 2014.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 7—COMMITMENTS AND CONTINGENCIES Environmental Matters The Company’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Company does not consider the estimated remediation costs that could result from any environmental site assessments to be significant to the consolidated financial statements and no provision for potential remediation costs has been made. Litigation From time to time, the Company is involved in legal actions and claims arising in the ordinary course of business. The Company believes existing claims as of June 30, 2015 will be resolved without material adverse effect to the Company’s consolidated financial statements.

Credit Facility

Credit Facility	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Credit Facility	NOTE 8—CREDIT FACILITY The Company’s amended credit agreement (the “Senior Line of Credit”) has a maximum credit amount of $1.0 billion. All unpaid principal and interest for the Senior Line of Credit is due February 3, 2017. The borrowing base was $700.0 million at December 31, 2014. Our semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base to $600.0 million, effective April 10, 2015. The amount of the borrowing base is derived from the value of the Company’s oil and natural gas properties determined by the lender syndicate using pricing assumptions that often differ from strip prices. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes. On January 23, 2015, the Senior Line of Credit was amended and restated. Borrowings under the Senior Line of Credit bear interest at LIBOR plus a margin between 1.50% and 2.50%, or prime rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan. The prime rate is determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. The weighted-average interest rate of the Senior Line of Credit was 3.75% and 2.41% as of June 30, 2015 and December 31, 2014, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.50% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Senior Line of Credit is secured by a majority of the Company’s oil and natural gas production and assets. The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of Credit requires the Company to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of June 30, 2015, the Company was in compliance with all financial covenants in the Senior Line of Credit. The aggregate principal balance outstanding was $6.0 million and $394.0 million at June 30, 2015 and December 31, 2014, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $594.0 million and $306.0 million at June 30, 2015 and December 31, 2014, respectively. Refer to Note 1 – Business and Basis of Presentation for a discussion of the use of proceeds from the IPO.

Incentive Compensation

Incentive Compensation	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Incentive Compensation	NOTE 9—INCENTIVE COMPENSATION Effective May 6, 2015, the Company’s general partner adopted a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Company’s general partner and certain employees and consultants of the Company and its affiliates are eligible to receive awards with respect to the Company’s common or subordinated units. In connection with the IPO, outstanding restricted common units in the Predecessor were exchanged for restricted common and subordinated units in the Company under the 2015 LTIP. Additionally, a provision contained in certain of the Predecessor’s restricted unit agreements that allowed award recipients to request cash settlement for up to 50% of their restricted unit awards granted prior to December 31, 2014 was removed; as such, these awards are no longer classified as liability awards. The Company’s general partner currently intends to grant new equity-based awards under the 2015 LTIP only with respect to common units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. On May 6, 2015, in conjunction with the adoption of the 2015 LTIP, the Board of Directors of the Company’s general partner (the “Board”) approved a grant of awards to each of the Company’s executive officers, certain other employees, and each of the non-employee directors of the Company’s general partner. These awards consisted of restricted common units, restricted performance units (in the form of phantom units) with distribution equivalent rights, fully vested common units, and cash awards. The grants included 1,034,013 restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through April 1, 2019. The holders of restricted common unit awards have all of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method. The Board also approved a grant of 947,142 restricted performance units that are subject to both performance-based and service-based vesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Company’s performance over each of the four 12-month performance periods commencing April 1, 2015. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible to become earned as follows: 16.66%, 16.67%, and 16.67% of the performance units may become earned in each of the 12-month performance periods that end on March 31, 2016, March 31, 2017 and March 31, 2018, respectively. The remaining 50% of the restricted performance units are eligible to become earned during the final 12-month performance period that ends on March 31, 2019. If the performance criteria are not met for the final performance period, the awards allow for a make-up period ending on March 31, 2020. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Company’s estimate, are likely to vest, by the grant-date fair value and recognized using the accelerated attribution method. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital. Additionally, non-employee directors of the Company’s general partner received a one-time grant totaling 63,156 fully vested common units. Cash awards totaling $2.7 million with service-based graded vesting requirements through March 31, 2019 were also granted to certain other employees. The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and six months ended June 30, 2015 and 2014, respectively. Three Six Incentive compensation expense 2015 2014 2015 2014 (In thousands) Cash—long-term incentive plan $ 4,029 $ 2,506 $ 7,480 $ 5,725 Equity-based compensation—restricted common and subordinated units 2,668 1,716 3,950 3,432 Equity-based compensation—restricted performance units 1,260 — 1,260 — Board of Directors incentive plan 1,671 550 2,152 3,160 Total incentive compensation expense $ 9,628 $ 4,772 $ 14,842 $ 12,317

Redeemable Preferred Units

Redeemable Preferred Units	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Redeemable Preferred Units	NOTE 10—REDEEMABLE PREFERRED UNITS The Company has 117,963 and 157,203 preferred units outstanding with a book value of $120.9 million and $161.2 million as of June 30, 2015 and December 31, 2014, respectively, which includes accrued dividends of $2.9 million and $4.0 million as of June 30, 2015 and December 31, 2014, respectively. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Company. The preferred units are entitled to an annual dividend coupon of 10% of the funded capital of the preferred units, payable on a quarterly basis in arrears. The Company accrued dividends on the preferred units of $2.9 million and $3.9 million for the quarters ended June 30, 2015 and 2014, respectively. The preferred units are convertible into common and subordinated units at any time at the option of the preferred unitholders. The preferred units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO. The owners of the preferred units could elect to have the Company redeem up to 25% per year of their initial balance of preferred units at face value, plus any accrued and unpaid dividends, on December 31 of each year from 2014 to 2017. The Company shall have the right, at its sole option, to redeem an amount of preferred units equal to the units being redeemed by an owner of preferred units on each December 31. Any amount of a given year’s 25% of preferred units not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 of the following year. For the six months ended June 30, 2015, 39,240 preferred units totaling $39.2 million were converted into the equivalent of 1,190,664 common units and 1,559,502 subordinated units on an adjusted basis, which included the automatic conversion on January 1, 2015.

Earnings Per Unit

Earnings Per Unit	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Earnings Per Unit	NOTE 11—EARNINGS PER UNIT We apply the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Company’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Company is allocated to our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The redeemable preferred units could be converted into 3.6 million common units and 4.7 million subordinated units as of June 30, 2015, and 4.8 million common units and 6.2 million subordinated units, on an adjusted basis, as of June 30, 2014. At June 30, 2015 and 2014, if the redeemable preferred units were converted to common and subordinated units, the effect would be anti-dilutive. Therefore, the redeemable preferred units are not included in the diluted EPU calculation. The Company’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Company assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. As of June 30, 2015, there were no units related to the Company’s restricted performance unit awards included in the calculation of diluted EPU. The following table sets forth the computation of basic and diluted earnings per common and subordinated unit: Three Six 2015 2014 2015 2014 (In thousands, except per unit amounts) Net income (loss) $ (122,766 ) $ 62,111 $ (105,467 ) $ 131,995 Net (income) loss attributable to Predecessor 16,849 (62,111 ) (450 ) (131,995 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 140 — 140 — Dividends on preferred units subsequent to initial public offering (1,810 ) — (1,810 ) — Net loss attributable to the general partner and limited partners subsequent to initial public offering $ (107,587 ) $ — $ (107,587 ) $ — Allocation of net loss subsequent to initial public offering attributable to: General partner interest $ — $ — Common limited partner interests (54,109 ) (54,109 ) Subordinated limited partner interests (53,478 ) (53,478 ) $ (107,587 ) $ (107,587 ) Net loss attributable to limited partners per unit: Per common limited partner unit (basic and diluted) $ (0.56 ) $ (0.56 ) Weighted average common limited partner units outstanding (basic and diluted) 96,178 96,178 Per subordinated limited partner unit (basic and diluted) $ (0.56 ) $ (0.56 ) Weighted average subordinated limited partner units outstanding (basic and diluted) 95,057 95,057

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE 12—SUBSEQUENT EVENTS On July 15, 2015, the Company closed a transaction to purchase mineral and royalty interests in the Permian Basin for $7.8 million. On August 12, 2015, the Board approved a prorated distribution for the period May 6, 2015 through June 30, 2015 of $0.1615 per unit for common and subordinated unitholders. Distributions will be payable on August 27, 2015 to unitholders of record at the close of business on August 20, 2015.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
New Accounting Pronouncements	New accounting pronouncements Revenue Recognition In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance will be material to the Company’s consolidated financial statements and related disclosures. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. The Company does not expect the impact of adopting this guidance will be material to the Company’s consolidated financial statements and related disclosures.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation Liability	The following table describes changes to the Company’s ARO liability during the period: For the six months ended June 30, 2015 (In thousands) Beginning asset retirement obligations $ 9,381 Liabilities incurred 92 Liabilities settled (105 ) Accretion expense 540 Ending asset retirement obligations $ 9,908

Derivatives and Financial Ins21

Derivatives and Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative [Line Items]
Summary of Fair Value and Classification of Derivative Instruments	The table below summarizes the fair value and classification of the Company’s derivative instruments: As of June 30, 2015 (In thousands) Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet Assets: Current asset Commodity derivative assets $ 11,385 $ (3,091 ) $ 8,294 Long-term asset Deferred charges and other long-term assets 109 (109 ) — Total assets $ 11,494 $ (3,200 ) $ 8,294 Liabilities: Current liability Commodity $ 4,199 $ (3,091 ) $ 1,108 Long-term liability Commodity derivative liabilities 2,959 (109 ) 2,850 Total liabilities $ 7,158 $ (3,200 ) $ 3,958 As of December 31, 2014 (In thousands) Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet Assets: Current asset Commodity derivative assets $ 37,656 $ (185 ) $ 37,471 Long-term asset Deferred charges and other long-term assets — — — Total assets $ 37,656 $ (185 ) $ 37,471 Liabilities: Current liability Commodity derivative liabilities $ 185 $ (185 ) $ — Long-term liability Commodity derivative liabilities — — — Total liabilities $ 185 $ (185 ) $ —
Changes in Fair Value of Company's Commodity Derivative Instruments	Changes in the fair value of the Company’s commodity derivative instruments (both assets and liabilities) are as follows: For the six months ended June 30, Derivatives not designated as hedging instruments under ASC 815 2015 2014 (In thousands) Beginning fair value of commodity derivative instruments $ 37,471 $ (1,812 ) Loss on oil derivative instruments (3,696 ) (6,456 ) Gain (loss) on natural gas derivative instruments 4,716 (1,887 ) Net cash (received) paid on settlements of oil derivative instruments (22,413 ) 273 Net cash (received) paid on settlements of natural gas derivative instruments (11,742 ) 2,670 Net change in fair value of commodity derivative instruments (33,135 ) (5,400 ) Ending fair value of commodity derivative instruments $ 4,336 $ (7,212 )
Oil and Natural Gas
Derivative [Line Items]
Summary of Open Derivative Contracts for Oil and Natural Gas	The Company had the following open derivative contracts for oil as of June 30, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Collars: Q2 2015 Collar contracts: Call Options 92,000 $ 102.73 $ 101.00 $ 104.00 Put Options 92,000 $ 86.14 $ 84.00 $ 90.00 Q3 2015 Collar contracts: Call Options 161,000 $ 102.45 $ 102.00 $ 103.55 Put Options 161,000 $ 84.88 $ 84.00 $ 87.00 Q4 2015 Collar contracts: Call Options 30,000 $ 102.00 $ 102.00 $ 102.00 Put Options 30,000 $ 85.00 $ 85.00 $ 85.00 Oil Swaps: Q2 2015 Swap contracts: 108,000 $ 57.69 $ 55.60 $ 58.77 Q3 2015 Swap contracts: 405,000 $ 58.99 $ 56.76 $ 60.22 Q4 2015 Swap contracts: 471,000 $ 60.60 $ 59.00 $ 61.71 2016 Swap contracts: 1,638,000 $ 58.21 $ 54.80 $ 63.07 2017 Swap contracts: 343,000 $ 63.28 $ 62.87 $ 63.65 The Company had the following open derivative contracts for natural gas as of June 30, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swaps: Q3 2015 Swap contracts: 7,590,000 $ 3.09 $ 2.84 $ 3.22 Q4 2015 Swap contracts: 6,900,000 $ 3.25 $ 2.88 $ 3.53 2016 Swap contracts: 22,940,000 $ 3.18 $ 3.03 $ 3.41 2017 Swap contracts: 4,640,000 $ 3.49 $ 3.43 $ 3.52 The Company entered into the following derivative contracts for oil subsequent to June 30, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swaps: Q3 2015 Swap contracts: 20,000 $ 46.88 $ 46.86 $ 46.90 Q4 2015 Swap contracts: 60,000 $ 48.13 $ 47.39 $ 49.18 2016 Swap contracts: 141,000 $ 50.95 $ 48.54 $ 53.30 2017 Swap contracts: 360,000 $ 53.95 $ 52.73 $ 54.38 The Company entered into the following derivative contracts for natural gas subsequent to June 30, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swaps: Q3 2015 Swap contracts: 280,000 $ 2.80 $ 2.80 $ 2.80 Q4 2015 Swap contracts: 700,000 $ 2.94 $ 2.82 $ 3.11 2016 Swap contracts: 1,310,000 $ 3.12 $ 3.00 $ 3.35 2017 Swap contracts: 5,010,000 $ 3.18 $ 3.14 $ 3.46

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Level 1 Level 2 Level 3 Netting Total (In thousands) As of June 30, 2015 Financial Assets Commodity derivative instruments $ — $ 11,494 $ — $ (3,200 ) $ 8,294 Financial Liabilities Commodity derivative instruments — 7,158 — (3,200 ) $ 3,958 As of December 31, 2014 Financial Assets Commodity derivative instruments $ — $ 37,656 $ — $ (185 ) $ 37,471 Financial Liabilities Commodity derivative instruments — 185 — (185 ) $ —
Schedule of Assets Measured at Fair Value on a Nonrecurring Basis	The following table presents information about the Company’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value Impairment (In thousands) As of June 30, 2015 Impaired oil and natural gas properties $ — $ — $ 89,671 $ 221,500 $ 131,829 As of December 31, 2014 Impaired oil and natural gas properties $ — $ — $ 81,864 $ 199,794 $ 117,930

Incentive Compensation (Tables)

Incentive Compensation (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Incentive Compensation Expense	The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and six months ended June 30, 2015 and 2014, respectively. Three Six Incentive compensation expense 2015 2014 2015 2014 (In thousands) Cash—long-term incentive plan $ 4,029 $ 2,506 $ 7,480 $ 5,725 Equity-based compensation—restricted common and subordinated units 2,668 1,716 3,950 3,432 Equity-based compensation—restricted performance units 1,260 — 1,260 — Board of Directors incentive plan 1,671 550 2,152 3,160 Total incentive compensation expense $ 9,628 $ 4,772 $ 14,842 $ 12,317

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings per Common and Subordinated Unit	The following table sets forth the computation of basic and diluted earnings per common and subordinated unit: Three Six 2015 2014 2015 2014 (In thousands, except per unit amounts) Net income (loss) $ (122,766 ) $ 62,111 $ (105,467 ) $ 131,995 Net (income) loss attributable to Predecessor 16,849 (62,111 ) (450 ) (131,995 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 140 — 140 — Dividends on preferred units subsequent to initial public offering (1,810 ) — (1,810 ) — Net loss attributable to the general partner and limited partners subsequent to initial public offering $ (107,587 ) $ — $ (107,587 ) $ — Allocation of net loss subsequent to initial public offering attributable to: General partner interest $ — $ — Common limited partner interests (54,109 ) (54,109 ) Subordinated limited partner interests (53,478 ) (53,478 ) $ (107,587 ) $ (107,587 ) Net loss attributable to limited partners per unit: Per common limited partner unit (basic and diluted) $ (0.56 ) $ (0.56 ) Weighted average common limited partner units outstanding (basic and diluted) 96,178 96,178 Per subordinated limited partner unit (basic and diluted) $ (0.56 ) $ (0.56 ) Weighted average subordinated limited partner units outstanding (basic and diluted) 95,057 95,057

Business and Basis of Present25

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions	May. 06, 2015USD ($)$ / sharesshares	Jun. 30, 2015StatesBasinsshares
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage		20.00%
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located | States		41
Number of onshore oil and natural gas producing basins | Basins		62
Common Units
Limited Partners Capital Account [Line Items]
Issuance of common units for initial public offering, net of offering costs, units		22,500,000
Common Units | Predecessor
Limited Partners Capital Account [Line Items]
Units exchanged in merger	72,574,715
Units conversion ratio as part of merger	12.9465
Common Units | IPO | Limited Partner
Limited Partners Capital Account [Line Items]
Issuance of common units for initial public offering, net of offering costs, units	22,500,000
Price per common unit (in dollars per unit) | $ / shares	$ 19
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions | $	$ 391.5
Subordinate Units | Predecessor
Limited Partners Capital Account [Line Items]
Units exchanged in merger	95,057,312
Units conversion ratio as part of merger	12.9465
Preferred Units | Predecessor
Limited Partners Capital Account [Line Items]
Units exchanged in merger	117,963
Units conversion ratio as part of merger	1

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations			$ 9,381
Liabilities incurred			92	$ 62
Liabilities settled			(105)
Accretion expense	$ 269	$ 148	540	$ 295
Ending asset retirement obligations	$ 9,908		$ 9,908

Derivatives and Financial Ins27

Derivatives and Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	$ 11,494	$ 37,656
Effect of Counterparty Netting, Assets	(3,200)	(185)
Net Carrying Value on Balance Sheet, Assets	8,294	37,471
Gross Fair Value, Liabilities	7,158	185
Effect of Counterparty Netting, Liabilities	(3,200)	(185)
Net Carrying Value on Balance Sheet, Liabilities	3,958
Commodity Derivative Assets, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	11,385	37,656
Effect of Counterparty Netting, Assets	(3,091)	(185)
Net Carrying Value on Balance Sheet, Assets	8,294	37,471
Deferred Charges and Other Long-term Assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	109
Effect of Counterparty Netting, Assets	(109)
Commodity Derivative Liabilities, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	4,199	185
Effect of Counterparty Netting, Liabilities	(3,091)	$ (185)
Net Carrying Value on Balance Sheet, Liabilities	1,108
Commodity Derivative Liabilities, Long-term
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	2,959
Effect of Counterparty Netting, Liabilities	(109)
Net Carrying Value on Balance Sheet, Liabilities	$ 2,850

Derivatives and Financial Ins28

Derivatives and Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative [Line Items]
Gain (loss) on commodity derivative instruments	$ (18,627)	$ (2,348)	$ 1,020	$ (8,343)
Net cash (received) paid on settlements of derivative instruments			(34,155)	2,943
Not Designated as Hedging Instrument
Derivative [Line Items]
Beginning fair value of commodity derivative instruments			37,471	(1,812)
Net change in fair value of commodity derivative instruments			(33,135)	(5,400)
Ending fair value of commodity derivative instruments	$ 4,336	$ (7,212)	4,336	(7,212)
Oil | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments			(3,696)	(6,456)
Net cash (received) paid on settlements of derivative instruments			(22,413)	273
Natural Gas | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments			4,716	(1,887)
Net cash (received) paid on settlements of derivative instruments			$ (11,742)	$ 2,670

Derivatives and Financial Ins29

Derivatives and Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument	Aug. 13, 2015MMBTU$ / bbl$ / MMBTUbbl	Jun. 30, 2015MMBTU$ / bbl$ / MMBTUbbl
Oil | Q2 2015 | 2015 Collar Contracts | Call Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		92,000
Derivative Contract, Weighted Average Price		102.73
Derivative Contract, Price Range Low		101
Derivative Contract, Price Range High		104
Oil | Q2 2015 | 2015 Collar Contracts | Put Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		92,000
Derivative Contract, Weighted Average Price		86.14
Derivative Contract, Price Range Low		84
Derivative Contract, Price Range High		90
Oil | Q2 2015 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		108,000
Derivative Contract, Weighted Average Price		57.69
Derivative Contract, Price Range Low		55.60
Derivative Contract, Price Range High		58.77
Oil | Q3 2015 | 2015 Collar Contracts | Call Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		161,000
Derivative Contract, Weighted Average Price		102.45
Derivative Contract, Price Range Low		102
Derivative Contract, Price Range High		103.55
Oil | Q3 2015 | 2015 Collar Contracts | Put Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		161,000
Derivative Contract, Weighted Average Price		84.88
Derivative Contract, Price Range Low		84
Derivative Contract, Price Range High		87
Oil | Q3 2015 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		405,000
Derivative Contract, Weighted Average Price		58.99
Derivative Contract, Price Range Low		56.76
Derivative Contract, Price Range High		60.22
Oil | Q3 2015 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | bbl	20,000
Derivative Contract, Weighted Average Price	46.88
Derivative Contract, Price Range Low	46.86
Derivative Contract, Price Range High	46.90
Oil | Q4 2015 | 2015 Collar Contracts | Call Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		30,000
Derivative Contract, Weighted Average Price		102
Derivative Contract, Price Range Low		102
Derivative Contract, Price Range High		102
Oil | Q4 2015 | 2015 Collar Contracts | Put Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		30,000
Derivative Contract, Weighted Average Price		85
Derivative Contract, Price Range Low		85
Derivative Contract, Price Range High		85
Oil | Q4 2015 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		471,000
Derivative Contract, Weighted Average Price		60.60
Derivative Contract, Price Range Low		59
Derivative Contract, Price Range High		61.71
Oil | Q4 2015 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | bbl	60,000
Derivative Contract, Weighted Average Price	48.13
Derivative Contract, Price Range Low	47.39
Derivative Contract, Price Range High	49.18
Oil | 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		1,638,000
Derivative Contract, Weighted Average Price		58.21
Derivative Contract, Price Range Low		54.80
Derivative Contract, Price Range High		63.07
Oil | 2016 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | bbl	141,000
Derivative Contract, Weighted Average Price	50.95
Derivative Contract, Price Range Low	48.54
Derivative Contract, Price Range High	53.30
Oil | 2017 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		343,000
Derivative Contract, Weighted Average Price		63.28
Derivative Contract, Price Range Low		62.87
Derivative Contract, Price Range High		63.65
Oil | 2017 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | bbl	360,000
Derivative Contract, Weighted Average Price	53.95
Derivative Contract, Price Range Low	52.73
Derivative Contract, Price Range High	54.38
Natural Gas | Q3 2015 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		7,590,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.09
Derivative Contract, Price Range Low | $ / MMBTU		2.84
Derivative Contract, Price Range High | $ / MMBTU		3.22
Natural Gas | Q3 2015 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	280,000
Derivative Contract, Weighted Average Price | $ / MMBTU	2.80
Derivative Contract, Price Range Low | $ / MMBTU	2.80
Derivative Contract, Price Range High | $ / MMBTU	2.80
Natural Gas | Q4 2015 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		6,900,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.25
Derivative Contract, Price Range Low | $ / MMBTU		2.88
Derivative Contract, Price Range High | $ / MMBTU		3.53
Natural Gas | Q4 2015 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	700,000
Derivative Contract, Weighted Average Price | $ / MMBTU	2.94
Derivative Contract, Price Range Low | $ / MMBTU	2.82
Derivative Contract, Price Range High | $ / MMBTU	3.11
Natural Gas | 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		22,940,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.18
Derivative Contract, Price Range Low | $ / MMBTU		3.03
Derivative Contract, Price Range High | $ / MMBTU		3.41
Natural Gas | 2016 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	1,310,000
Derivative Contract, Weighted Average Price | $ / MMBTU	3.12
Derivative Contract, Price Range Low | $ / MMBTU	3
Derivative Contract, Price Range High | $ / MMBTU	3.35
Natural Gas | 2017 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		4,640,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.49
Derivative Contract, Price Range Low | $ / MMBTU		3.43
Derivative Contract, Price Range High | $ / MMBTU		3.52
Natural Gas | 2017 | Swap Contracts | Swap | Subsequent Events
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	5,010,000
Derivative Contract, Weighted Average Price | $ / MMBTU	3.18
Derivative Contract, Price Range Low | $ / MMBTU	3.14
Derivative Contract, Price Range High | $ / MMBTU	3.46

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	$ 11,494	$ 37,656
Effect of Counterparty Netting, Assets	(3,200)	(185)
Net Carrying Value on Balance Sheet, Assets	8,294	37,471
Gross Fair Value, Liabilities	7,158	185
Effect of Counterparty Netting, Liabilities	(3,200)	(185)
Net Carrying Value on Balance Sheet, Liabilities	3,958
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	11,494	37,656
Effect of Counterparty Netting, Assets	(3,200)	(185)
Net Carrying Value on Balance Sheet, Assets	8,294	37,471
Gross Fair Value, Liabilities	7,158	185
Effect of Counterparty Netting, Liabilities	(3,200)	$ (185)
Net Carrying Value on Balance Sheet, Liabilities	$ 3,958

Fair Value Measurements - Sch31

Fair Value Measurements - Schedule of Assets Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Impairment	$ 118,362	$ 131,829
Fair Value Measurements, Nonrecurring Basis
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Net Book Value	221,500	221,500	$ 199,794
Impaired oil and natural gas properties, Impairment		131,829	117,930
Fair Value Measurements, Nonrecurring Basis | Level 3
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	$ 89,671	$ 89,671	$ 81,864

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Predecessor - Officer - USD ($) $ in Millions	Apr. 15, 2010	Jun. 30, 2014
Related Party Transaction [Line Items]
Promissory note, executed amount	$ 0.5
Promissory notes receivable		$ 0.1

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	Jun. 30, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
Provision for remediation costs	$ 0

Credit Facility - Additional In

Credit Facility - Additional Information (Details) - USD ($)	Jan. 23, 2015	Jun. 30, 2015	Apr. 10, 2015	Dec. 31, 2014	Jun. 28, 2013
Line Of Credit Facility [Line Items]
Credit facilities		$ 6,000,000		$ 394,000,000
Senior Line of Credit
Line Of Credit Facility [Line Items]
Line of credit, maximum borrowing capacity					$ 1,000,000,000
Line of credit, borrowing base			$ 600,000,000	$ 700,000,000
Line of credit facility, expiration date		Feb. 3, 2017
Line of credit, prime rate description		The prime rate is determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum
Line of credit, weighted average interest rate		3.75%		2.41%
Line of credit, accrued interest periodic payments		Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days in which case interest is payable at the end of every 90-day period.
Line of credit facility, frequency of commitment fee payment		Commitment fee is payable at the end of each calendar
Credit facilities		$ 6,000,000		$ 394,000,000
Line of credit, unused portion of current borrowing base		$ 594,000,000		$ 306,000,000
Senior Line of Credit | Minimum
Line Of Credit Facility [Line Items]
Line of credit, current ratio		100.00%
Senior Line of Credit | Maximum
Line Of Credit Facility [Line Items]
Line of credit, ratio of total debt to EBITDAX		350.00%
Senior Line of Credit | LIBOR Plus Margin Rate | Minimum
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%
Senior Line of Credit | LIBOR Plus Margin Rate | Maximum
Line Of Credit Facility [Line Items]
Line of credit, interest rate	2.50%
Senior Line of Credit | Prime Rate Plus Margin Rate | Minimum
Line Of Credit Facility [Line Items]
Line of credit, interest rate	0.50%
Senior Line of Credit | Prime Rate Plus Margin Rate | Maximum
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%
Senior Line of Credit | Federal funds effective rate
Line Of Credit Facility [Line Items]
Line of credit, interest rate	0.50%
Senior Line of Credit | Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Line of credit, commitment fee payable rate		0.375%
Senior Line of Credit | Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Line of credit, commitment fee payable rate		0.50%

Incentive Compensation - Additi

Incentive Compensation - Additional Information (Details) - May. 06, 2015 - 2015 LTIP $ in Millions	USD ($)Timeshares
Other Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash awards granted | $	$ 2.7
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units	1,034,013
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units	947,142
Target number of common units, Minimum | Time	0
Target number of common units, Maximum | Time	2
Restricted Performance Units | March 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of restricted performance units are eligible to become earned	16.66%
Restricted Performance Units | March 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of restricted performance units are eligible to become earned	16.67%
Restricted Performance Units | March 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of restricted performance units are eligible to become earned	16.67%
Restricted Performance Units | March 31, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of restricted performance units are eligible to become earned	50.00%
Common Units | Non-employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested	63,156
Predecessor | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash settlement of restricted unit awards granted	50.00%

Incentive Compensation - Summar

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - 2015 LTIP - General and administrative expenses - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 4,029	$ 2,506	$ 7,480	$ 5,725
Total incentive compensation expense	9,628	4,772	14,842	12,317
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	2,668	1,716	3,950	3,432
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	1,260		1,260
Board of Director | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 1,671	$ 550	$ 2,152	$ 3,160

Redeemable Preferred Units - Ad

Redeemable Preferred Units - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 02, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Dec. 31, 2014
Class Of Stock [Line Items]
Preferred units, outstanding value		$ 120,904		$ 120,904	$ 161,165
Dividends on preferred units				$ 1,810
Preferred Units
Class Of Stock [Line Items]
Partners' equity, preferred units, outstanding		117,963		117,963	157,203
Preferred units, outstanding value		$ 120,900		$ 120,900	$ 161,200
Accrued dividends		2,900		$ 2,900	$ 4,000
Preferred units dividend coupon rate				10.00%
Dividends on preferred units		$ 2,900	$ 3,900
Adjusted conversion price		$ 14.2683		$ 14.2683
Preferred units, redemption terms				The owners of the preferred units could elect to have the Company redeem up to 25% per year of their initial balance of preferred units at face value, plus any accrued and unpaid dividends, on December 31 of each year from 2014 to 2017. The Company shall have the right, at its sole option, to redeem an amount of preferred units equal to the units being redeemed by an owner of preferred units on each December 31. Any amount of a given year’s 25% of preferred units not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 of the following year.
Redemption percentage				25.00%
Preferred units redemption period start date				Dec. 31, 2014
Preferred units redemption period end date				Dec. 31, 2017
Number of preferred units converted	39,223	39,240		39,240
Conversion of preferred units to common units	$ 39,200			$ 39,200
Common Units
Class Of Stock [Line Items]
Adjusted conversion rate				30.3431
Conversion of preferred units	1,190,148			1,190,664
Subordinate Units
Class Of Stock [Line Items]
Adjusted conversion rate				39.7427
Conversion of preferred units	1,558,826			1,559,502

Earnings Per Unit - Additional

Earnings Per Unit - Additional Information (Details) - shares	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Restricted Performance Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	0
Common Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	3,600,000	4,800,000
Subordinate Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	4,700,000	6,200,000

Earnings Per Unit - Computation

Earnings Per Unit - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share Basic [Line Items]
Net income (loss)	$ (122,766)	$ 62,111	$ (105,467)	$ 131,995
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING	140		140
DIVIDENDS ON PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(1,810)		(1,810)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND LIMITED PARTNERS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(107,587)		(107,587)
Allocation of net loss subsequent to initial public offering attributable to:
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND LIMITED PARTNERS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(107,587)		(107,587)
Common Units
Allocation of net loss subsequent to initial public offering attributable to:
Limited partner interests	$ (54,109)		$ (54,109)
Net loss attributable to limited partners per unit:
Per limited partner unit (basic)	$ (0.56)		$ (0.56)
Per limited partner unit (diluted)	$ (0.56)		$ (0.56)
Weighted average limited partner units outstanding (basic and diluted)	96,178		96,178
Subordinate Units
Allocation of net loss subsequent to initial public offering attributable to:
Limited partner interests	$ (53,478)		$ (53,478)
Net loss attributable to limited partners per unit:
Per limited partner unit (basic)	$ (0.56)		$ (0.56)
Per limited partner unit (diluted)	$ (0.56)		$ (0.56)
Weighted average limited partner units outstanding (basic and diluted)	95,057		95,057
Predecessor
Earnings Per Share Basic [Line Items]
Net income (loss)	$ (16,849)	$ 62,111	$ 450	$ 131,995

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Aug. 13, 2015	Jul. 15, 2015	Jun. 30, 2015	Jun. 30, 2014
Subsequent Event [Line Items]
Purchase of mineral and royalty interest			$ 9,574	$ 29,431
Subsequent Events
Subsequent Event [Line Items]
Purchase of mineral and royalty interest		$ 7,800
Distribution declaration date	Aug. 12, 2015
Distribution date of record	Aug. 20, 2015
Distribution date	Aug. 27, 2015
Subsequent Events | Common Units
Subsequent Event [Line Items]
Prorated quarterly cash distribution declared	$ 0.1615
Subsequent Events | Subordinate Units
Subsequent Event [Line Items]
Prorated quarterly cash distribution declared	$ 0.1615