Black Stone Minerals (BSM) 10-Q 9 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 05, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
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		95,740,308
Subordinated Units
Document Information [Line Items]
Entity Partnership Units Outstanding		95,189,076
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding		52,691

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 9,770	$ 13,233
Accounts receivable	53,568	41,246
Commodity derivative assets	13,412	48,260
Prepaid expenses and other current assets	2,160	856
TOTAL CURRENT ASSETS	78,910	103,595
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $609,783 and $524,563 at June 30, 2016 and December 31, 2015, respectively	2,646,558	2,482,211
Accumulated depreciation, depletion, amortization, and impairment	(1,601,401)	(1,543,796)
Oil and natural gas properties, net	1,045,157	938,415
Other property and equipment, net of accumulated depreciation of $14,693 and $14,660 at June 30, 2016 and December 31, 2015, respectively	151	179
NET PROPERTY AND EQUIPMENT	1,045,308	938,594
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	2,612	19,247
TOTAL ASSETS	1,126,830	1,061,436
CURRENT LIABILITIES
Accounts payable	5,160	5,036
Accrued liabilities	36,475	58,003
Commodity derivative liabilities	1,835
TOTAL CURRENT LIABILITIES	43,470	63,039
LONG-TERM LIABILITIES
Credit facility	285,000	66,000
Accrued incentive compensation	5,264	7,902
Commodity derivative liabilities	1,101
Deferred revenue	3,477	3,257
Asset retirement obligations	11,240	10,585
TOTAL LIABILITIES	349,552	150,783
COMMITMENTS AND CONTINGENCIES (Note 8)
MEZZANINE EQUITY
Partners' equity - redeemable preferred units, 53 and 77 units outstanding at June 30, 2016 and December 31, 2015, respectively	54,001	79,162
EQUITY
Noncontrolling interests	1,083	1,144
TOTAL EQUITY	723,277	831,491
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	1,126,830	1,061,436
Common Units
EQUITY
Partners' equity - units	511,862	574,648
Subordinated Units
EQUITY
Partners' equity - units	$ 210,332	$ 255,699

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Oil and natural gas properties, unproved property costs	$ 609,783	$ 524,563
Other property and equipment accumulated depreciation and amortization	$ 14,693	$ 14,660
Preferred Units
Partners' equity, preferred units, outstanding	52,691	77,216
Common Units
Partners' equity - units, outstanding	95,736,000	96,162,000
Subordinated Units
Partners' equity - units, outstanding	95,189,000	95,057,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUE
Oil and condensate sales	$ 34,553	$ 46,293	$ 61,801	$ 82,456
Natural gas and natural gas liquids sales	21,607	28,968	46,719	60,608
Gain (loss) on commodity derivative instruments	(30,733)	(18,627)	(20,107)	1,020
Lease bonus and other income	15,142	8,169	16,537	11,780
TOTAL REVENUE	40,569	64,803	104,950	155,864
OPERATING (INCOME) EXPENSE
Lease operating expense	4,283	5,483	9,172	11,616
Production costs and ad valorem taxes	7,012	9,819	14,074	18,075
Exploration expense	629	158	637	197
Depreciation, depletion and amortization	29,202	32,235	50,923	60,126
Impairment of oil and natural gas properties	679	118,362	6,775	131,829
General and administrative	18,134	19,718	35,535	34,536
Accretion of asset retirement obligations	200	269	474	540
Gain on sale of assets, net	(92)	(17)	(4,772)	(24)
TOTAL OPERATING EXPENSE	60,047	186,027	112,818	256,895
INCOME FROM OPERATIONS	(19,478)	(121,224)	(7,868)	(101,031)
OTHER INCOME (EXPENSE)
Interest and investment income	38	27	191	28
Interest expense	(1,443)	(1,715)	(2,491)	(4,660)
Other income	73	146	107	196
TOTAL OTHER EXPENSE	(1,332)	(1,542)	(2,193)	(4,436)
NET LOSS	(20,810)	(122,766)	(10,061)	(105,467)
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING	9	140	7	140
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(1,310)	(1,810)	(3,114)	(1,810)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(22,111)	(107,587)	(13,168)	(107,587)
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(22,111)	(107,587)	(13,168)	(107,587)
Predecessor
OTHER INCOME (EXPENSE)
NET LOSS		16,849		(450)
Common Units
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of net loss	$ (7,445)	$ (54,109)	$ 862	$ (54,109)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic)	$ (0.08)	$ (0.56)	$ 0.01	$ (0.56)
Weighted average units outstanding (basic)	96,356	96,178	96,418	96,178
Per unit (diluted)	$ (0.08)	$ (0.56)	$ 0.01	$ (0.56)
Weighted average units outstanding (diluted)	96,418	96,178	96,481	96,178
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit	$ 0.26250		$ 0.52500
Subordinated Units
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of net loss	$ (14,666)	$ (53,478)	$ (14,030)	$ (53,478)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic)	$ (0.15)	$ (0.56)	$ (0.15)	$ (0.56)
Weighted average units outstanding (basic)	95,189	95,057	95,092	95,057
Per unit (diluted)	$ (0.15)	$ (0.56)	$ (0.15)	$ (0.56)
Weighted average units outstanding (diluted)	95,092	95,057	95,092	95,057
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit	$ 0.18375		$ 0.36750

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Noncontrolling Interest	Common Units	Subordinated Units	Partners Equity Common Units	Partners Equity Subordinated Units
Beginning balance at Dec. 31, 2015	$ 831,491	$ 1,144			$ 574,648	$ 255,699
Beginning balance, units at Dec. 31, 2015			96,162	95,057
Restricted units granted, net of forfeitures			956	(38)
Equity-based compensation	9,908				8,732	1,176
Conversion of redeemable preferred units	6,064				2,625	3,439
Conversion of redeemable preferred units, units			184	241
Repurchases of common and subordinated units	(24,696)				(23,888)	(808)
Repurchase of common and subordinated units, units			(1,566)	(71)
Distributions	(85,920)	(54)			(50,722)	(35,144)
Charges to partners' equity for accrued distribution equivalent rights	(395)				(395)
Net income (loss)	(10,061)	(7)			2,431	(12,485)
Distributions on redeemable preferred units	(3,114)				(1,569)	(1,545)
Ending balance at Jun. 30, 2016	$ 723,277	$ 1,083			$ 511,862	$ 210,332
Ending balance, units at Jun. 30, 2016			95,736	95,189

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (10,061)	$ (105,467)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	50,923	60,126
Impairment of oil and natural gas properties	6,775	131,829
Accretion of asset retirement obligations	474	540
Amortization of deferred charges	394	482
(Gain) loss on commodity derivative instruments	20,107	(1,020)
Net cash received on settlement of commodity derivative instruments	33,918	34,155
Equity-based compensation	25,139	7,362
Gain on sale of assets, net	(4,772)	(24)
Changes in operating assets and liabilities:
Accounts receivable	(6,585)	19,881
Prepaid expenses and other current assets	(1,003)	(912)
Accounts payable and accrued liabilities	(31,859)	(2,273)
Deferred revenue	221	(490)
Settlement of asset retirement obligations	(127)	(105)
NET CASH PROVIDED BY OPERATING ACTIVITIES	83,544	144,084
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties	(36,710)	(32,819)
Purchase of other property and equipment	(5)	(28)
Proceeds from the sale of oil and natural gas properties	177	406
Acquisitions of oil and natural gas properties	(136,340)	(9,574)
NET CASH USED IN INVESTING ACTIVITIES	(172,878)	(42,015)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs		399,394
Payments for capitalized offering costs	(301)
Borrowings under senior line of credit	230,000	123,600
Repayments of borrowings under senior line of credit	(11,000)	(511,600)
Distributions to noncontrolling interests	(54)	(122)
Redemptions of redeemable preferred units	(18,461)
Repurchases of common and subordinated units	(24,696)	(3,015)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	85,871	(110,824)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(3,463)	(8,755)
CASH AND CASH EQUIVALENTS - beginning of the period	13,233	14,803
CASH AND CASH EQUIVALENTS - end of the period	9,770	6,048
SUPPLEMENTAL DISCLOSURE
Interest paid	1,928	4,192
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		(450)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders		(112,210)
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(85,866)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (3,751)	$ (6,871)

Business and Basis of Presentat

Business and Basis of Presentation	6 Months Ended
	Jun. 30, 2016
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 was 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 “Partnership” 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, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. All of these interests are non-cost-bearing and are collectively referred to as “mineral and royalty interests.” As of June 30, 2016, the Partnership’s mineral and royalty interests were located in most of the major onshore oil and natural gas producing basins spread across 41 states and 61 onshore oil and natural gas producing basins of the continental United States. The Partnership 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 Partnership. 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 months and six months ended June 30, 2016 are not necessarily indicative of the results to be expected for the full year. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, 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 Partnership 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, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant accounting policies: New accounting pronouncements In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition . The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures and has not yet determined the method by which it will adopt the standard. In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842) The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent put and call options in debt instruments In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net) The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of credit losses on financial instruments

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2016
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 Partnership’s working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of its properties, a credit-adjusted risk-free 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 Partnership’s ARO liability during the period: For the six months ended June 30, 2016 (In thousands) Beginning asset retirement obligations $ 10,585 Liabilities incurred 172 Liabilities settled (127 ) Accretion expense 474 Revisions 136 Ending asset retirement obligations $ 11,240

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Acquisitions	NOTE 4—ACQUISITIONS Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at historical cost. On January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for $10.0 million. On June 15, 2016, the Partnership acquired an oil and natural gas mineral package primarily located in Weld County, Colorado for $34.0 million. The following table summarizes the fair values assigned to the properties acquired: (In thousands) Proved oil and natural gas properties $ 18,948 Unproved oil and natural gas properties 14,082 Net working capital 1,038 Asset retirement obligations (50 ) Purchase price allocation $ 34,018 On June 17, 2016, the Partnership acquired a diverse oil and natural gas mineral package from Freeport-McMoRan Oil and Gas, Inc. for $87.9 million. The following table summarizes the fair values assigned to the properties acquired: (In thousands) Proved oil and natural gas properties $ 20,637 Unproved oil and natural gas properties 65,745 Net working capital 1,488 Purchase price allocation $ 87,870

Derivatives and Financial Instr

Derivatives and Financial Instruments	6 Months Ended
	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivatives and Financial Instruments	NOTE 5—DERIVATIVES AND FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses derivative instruments. From time to time, such instruments may include fixed-price-swap contracts, fixed price contracts, costless collars, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. As of June 30, 2016, the Partnership’s open derivative contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership will receive from, or pay to, the counterparty the difference between the fixed-swap price and the market price on the settlement date. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change. All derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of June 30, 2016 and December 31, 2015. See Note 6 – Fair Value Measurement for further discussion. The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As of June 30, 2016 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (In thousands) Assets: Current asset Commodity derivative assets $ 15,778 $ (2,366 ) $ 13,412 Long-term asset Deferred charges and other long-term assets 212 (179 ) 33 Total assets $ 15,990 $ (2,545 ) $ 13,445 Liabilities: Current liability Commodity $ 4,201 $ (2,366 ) $ 1,835 Long-term liability Commodity derivative liabilities 1,280 (179 ) 1,101 Total liabilities $ 5,481 $ (2,545 ) $ 2,936 As of December 31, 2015 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (In thousands) Assets: Current asset Commodity derivative assets $ 48,260 $ — $ 48,260 Long-term asset Deferred charges and other long-term assets 16,274 — 16,274 Total assets $ 64,534 $ — $ 64,534 Liabilities: Current liability Commodity $ — $ — $ — Long-term liability Commodity derivative liabilities — — — Total liabilities $ — $ — $ — Changes in the fair values of the Partnership’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 Partnership’s commodity derivative instruments (both assets and liabilities) are as follows: For the six months ended June 30, Derivatives not designated as hedging instruments 2016 2015 (In thousands) Beginning fair value of commodity derivative instruments $ 64,534 $ 37,471 Loss on oil derivative instruments (12,615 ) (3,696 ) Gain (loss) on natural gas derivative instruments (7,492 ) 4,716 Net cash received on settlements of oil derivative instruments (18,766 ) (22,413 ) Net cash received on settlements of natural gas derivative instruments (15,152 ) (11,742 ) Net change in fair value of commodity derivative instruments (54,025 ) (33,135 ) Ending fair value of commodity derivative instruments $ 10,509 $ 4,336 The Partnership had the following open derivative contracts for oil as of June 30, 2016: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swap Contracts: 2016 Second Quarter 183,000 $ 53.46 $ 33.60 $ 61.96 Third Quarter 525,000 54.62 34.41 62.53 Fourth Quarter 478,000 56.26 36.31 63.07 2017 First Quarter 364,000 $ 62.69 $ 52.73 $ 63.65 Second Quarter 339,000 54.00 53.49 54.38 The Partnership had the following open derivative contracts for natural gas as of June 30, 2016: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: 2016 Third Quarter 7,320,000 $ 2.96 $ 2.23 $ 3.17 Fourth Quarter 6,570,000 3.12 2.29 3.41 2017 First Quarter 5,660,000 $ 3.44 $ 3.08 $ 3.52 Second Quarter 5,310,000 3.12 2.85 3.18 Third Quarter 4,910,000 2.93 2.90 2.94 Fourth Quarter 4,610,000 3.06 2.92 3.21 The Partnership entered into the following derivative contracts for natural gas subsequent to June 30, 2016: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: 2016 Third Quarter 240,000 $ 2.77 $ 2.77 $ 2.78 Fourth Quarter 360,000 3.00 2.81 3.23 2017 First Quarter 510,000 $ 3.34 $ 3.30 $ 3.38 Second Quarter 510,000 3.05 3.03 3.07 Third Quarter 510,000 3.10 3.08 3.11 Fourth Quarter 410,000 3.17 3.10 3.29

Fair Value Measurement

Fair Value Measurement	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	NOTE 6—FAIR VALUE MEASUREMENT Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820 establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. 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 Partnership’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 Partnership’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, 2016 or the year ended December 31, 2015. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership 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 5 – Derivatives and Financial Instruments for further discussion. The following table presents information about the Partnership’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, 2016 Financial Assets Commodity derivative instruments $ — $ 15,990 $ — $ (2,545 ) $ 13,445 Financial Liabilities Commodity derivative instruments — 5,481 — (2,545 ) 2,936 As of December 31, 2015 Financial Assets Commodity derivative instruments $ — $ 64,534 $ — $ — $ 64,534 Financial Liabilities Commodity derivative instruments — — — — — Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations 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. The Partnership has designated these measurements as Level 3. Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. 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. The Partnership’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, 2016 or December 31, 2015. The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value 1 Impairment (In thousands) June 30, 2016 Impaired oil and natural gas properties $ — $ — $ 543 $ 1,222 $ 679 March 31, 2016 Impaired oil and natural gas properties $ — $ — $ 2,499 $ 8,595 $ 6,096 June 30, 2015 Impaired oil and natural gas properties $ — $ — $ 71,845 $ 190,207 $ 118,362 March 31, 2015 Impaired oil and natural gas properties $ — $ — $ 17,826 $ 31,293 $ 13,467 1 Amount represents net book value at the date of assessment. The Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership compares the undiscounted projected future cash flows expected to the carrying amount to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership’s fair value assessment for recent acquisitions is included in Note 4 – Acquisitions. The estimated carrying value of all debt as of June 30, 2016 and December 31, 2015 approximated the fair value due to variable market rates of interest. These fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. The carrying value of receivables and payables approximate fair value due to the short-term nature of the instruments.

Credit Facility

Credit Facility	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Credit Facility	NOTE 7—CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement (the “Senior Line of Credit”). The Senior Line of Credit has a maximum credit amount of $1.0 billion. On October 28, 2015, the Senior Line of Credit was amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership’s semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. The next borrowing base redetermination is scheduled for October 2016. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes. Borrowings under the Senior Line of Credit bear interest at LIBOR plus a margin between 1.50% and 2.50%, or the Prime rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan, as detailed in the table below. 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. Borrowing Base Utilization Borrowing type <25% ≥25% <50% ≥ 50% <75% ≥75% <90% ≥90% Eurodollar Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % Base Rate Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % The weighted-average interest rate of the Senior Line of Credit was 2.45% and 1.92% as of June 30, 2016 and December 31, 2015, 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 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Senior Line of Credit is secured by substantially all of the Partnership’s producing oil and natural gas 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 Partnership 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, 2016, the Partnership was in compliance with all financial covenants for the Senior Line of Credit. The aggregate principal balance outstanding was $285.0 million and $66.0 million at June 30, 2016 and December 31, 2015, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $165.0 million and $484.0 million at June 30, 2016 and December 31, 2015, respectively.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 8—COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’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 Partnership does not consider the potential remediation costs that could result from issues identified in 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 Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of June 30, 2016 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

Incentive Compensation

Incentive Compensation	6 Months Ended
	Jun. 30, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Incentive Compensation	NOTE 9—INCENTIVE COMPENSATION On January 12, 2016, each non-employee director on the Board of Directors of the Partnership’s general partner (the “Board”) was granted 12,368 fully vested common units for service during 2015. On February 19, 2016, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted of restricted common units and restricted performance units (in the form of phantom units) with distribution equivalent rights. The grants included 717,654 restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 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 Compensation Committee of the Board also approved a grant of 717,654 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 Partnership’s average performance over each calendar year during the performance period commencing January 1, 2016. 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 at the end of the performance period on December 31, 2018. 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 Partnership’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. The Compensation Committee of the Board also approved the dollar-value targets for performance-based short-term incentive compensation for executive officers of the Partnership and certain other employees. The Partnership expects to ultimately settle the authorized awards at the end of the performance period in common units of the Partnership. On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the current quarter and the remaining unamortized expense of the awards will be amortized into equity-settled liabilities. The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three months and six months ended June 30, 2016 and 2015, respectively. Three Months Ended June 30, Six Months Ended June 30, Incentive compensation expense 2016 2015 2016 2015 (In thousands) (In thousands) Cash—long-term incentive plan $ 560 $ 4,029 $ 2,410 $ 7,480 Equity-based compensation—restricted common and subordinated units 3,190 2,668 5,933 3,950 Equity-based compensation—restricted performance units 5,426 1,260 8,039 1,260 Board of Directors incentive plan 476 1,671 957 2,152 Total incentive compensation expense $ 9,652 $ 9,628 $ 17,339 $ 14,842

Redeemable Preferred Units

Redeemable Preferred Units	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Redeemable Preferred Units	NOTE 10—REDEEMABLE PREFERRED UNITS The Partnership had 52,691 and 77,216 preferred units outstanding with a carrying value of $54.0 million and $79.2 million as of June 30, 2016 and December 31, 2015, respectively. The aforementioned amounts included accrued distributions of $1.3 million and $1.9 million as of June 30, 2016 and December 31, 2015, respectively. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The preferred units are entitled to an annual distribution of 10% of the funded capital of the preferred units, payable on a quarterly basis in arrears. 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 preferred unitholders can elect to have the Partnership redeem up to 25% per year of their initial balance of preferred units at face value, plus any accrued and unpaid distributions, as of December 31 of each year from 2014 to 2017. The Partnership 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 as of each December 31. Any amount of a given year’s 25% of preferred units not redeemed as of December 31 shall automatically convert to common and subordinated units in the following year. For the six months ended June 30, 2016, 18,461 preferred units were redeemed for $19.0 million, including accrued unpaid yield, and are included in accrued liabilities on the consolidated balance sheet. For the six months ended June 30, 2016, 6,064 preferred units totaling $6.1 million were converted into 184,006 common units and 240,986 subordinated units as a result of the mandatory conversion subsequent to December 31, 2015. For the year ended December 31, 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.

Earnings Per Unit

Earnings Per Unit	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings Per Unit	NOTE 11—EARNINGS PER UNIT The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’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 Partnership is allocated to the Partnership’s 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 1.6 million common units and 2.1 million subordinated units as of June 30, 2016. At June 30, 2016, 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 Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership 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. For the six months ended June 30, 2016, there were 125,487 common units related to the Partnership’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: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (In thousands, except per unit amounts) (In thousands, except per unit amounts) Net loss $ (20,810 ) $ (122,766 ) $ (10,061 ) $ (105,467 ) Net (income) loss attributable to Predecessor — 16,849 — (450 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 9 140 7 140 Distributions on redeemable preferred units subsequent to initial public offering (1,310 ) (1,810 ) (3,114 ) (1,810 ) Net loss attributable to the general partner and common and subordinated units subsequent to initial public offering $ (22,111 ) $ (107,587 ) $ (13,168 ) $ (107,587 ) Allocation of net income (loss) subsequent to initial public offering attributable to: General partner interest $ — $ — $ — $ — Common units (7,445 ) (54,109 ) 862 (54,109 ) Subordinated units (14,666 ) (53,478 ) (14,030 ) (53,478 ) $ (22,111 ) $ (107,587 ) $ (13,168 ) $ (107,587 ) Net income (loss) attributable to limited partners per common and subordinated units: Per common unit (basic) $ (0.08 ) $ (0.56 ) $ 0.01 $ (0.56 ) Weighted average common units outstanding (basic) 96,356 96,178 96,418 96,178 Per subordinated unit (basic) $ (0.15 ) $ (0.56 ) $ (0.15 ) $ (0.56 ) Weighted average subordinated units outstanding (basic) 95,189 95,057 95,092 95,057 Per common unit (diluted) $ (0.08 ) $ (0.56 ) $ 0.01 $ (0.56 ) Weighted average common units outstanding (diluted) 96,418 96,178 96,481 96,178 Per subordinated unit (diluted) $ (0.15 ) $ (0.56 ) $ (0.15 ) $ (0.56 ) Weighted average subordinated units outstanding (diluted) 95,092 95,057 95,092 95,057

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	NOTE 12—SUBSEQUENT EVENTS On August 8, 2016, the Board approved a distribution for the period April 1, 2016 to June 30, 2016 of $0.2875 per common unit and $0.18375 per subordinated unit. Distributions will be payable on August 25, 2016 to unitholders of record at the close of business on August 18, 2016.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	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 Partnership. 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 months and six months ended June 30, 2016 are not necessarily indicative of the results to be expected for the full year. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, 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 Partnership 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	Segment reporting
New Accounting Pronouncements	New accounting pronouncements In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition . The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures and has not yet determined the method by which it will adopt the standard. In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842) The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent put and call options in debt instruments In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net) The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of credit losses on financial instruments
Acquisitions	Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at historical cost.
Earnings Per Unit	The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’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 Partnership is allocated to the Partnership’s 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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation Liability	The following table describes changes to the Partnership’s ARO liability during the period: For the six months ended June 30, 2016 (In thousands) Beginning asset retirement obligations $ 10,585 Liabilities incurred 172 Liabilities settled (127 ) Accretion expense 474 Revisions 136 Ending asset retirement obligations $ 11,240

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2016
Weld County, Colorado
Schedule of Fair Values of the Properties Acquired	The following table summarizes the fair values assigned to the properties acquired: (In thousands) Proved oil and natural gas properties $ 18,948 Unproved oil and natural gas properties 14,082 Net working capital 1,038 Asset retirement obligations (50 ) Purchase price allocation $ 34,018
Freeport-McMo Ran oil and Gas, Inc
Schedule of Fair Values of the Properties Acquired	The following table summarizes the fair values assigned to the properties acquired: (In thousands) Proved oil and natural gas properties $ 20,637 Unproved oil and natural gas properties 65,745 Net working capital 1,488 Purchase price allocation $ 87,870

Derivatives and Financial Ins22

Derivatives and Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative [Line Items]
Summary of Fair Value and Classification of Derivative Instruments	The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As of June 30, 2016 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (In thousands) Assets: Current asset Commodity derivative assets $ 15,778 $ (2,366 ) $ 13,412 Long-term asset Deferred charges and other long-term assets 212 (179 ) 33 Total assets $ 15,990 $ (2,545 ) $ 13,445 Liabilities: Current liability Commodity $ 4,201 $ (2,366 ) $ 1,835 Long-term liability Commodity derivative liabilities 1,280 (179 ) 1,101 Total liabilities $ 5,481 $ (2,545 ) $ 2,936 As of December 31, 2015 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (In thousands) Assets: Current asset Commodity derivative assets $ 48,260 $ — $ 48,260 Long-term asset Deferred charges and other long-term assets 16,274 — 16,274 Total assets $ 64,534 $ — $ 64,534 Liabilities: Current liability Commodity $ — $ — $ — Long-term liability Commodity derivative liabilities — — — Total liabilities $ — $ — $ —
Changes in Fair Value of Company's Commodity Derivative Instruments	Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows: For the six months ended June 30, Derivatives not designated as hedging instruments 2016 2015 (In thousands) Beginning fair value of commodity derivative instruments $ 64,534 $ 37,471 Loss on oil derivative instruments (12,615 ) (3,696 ) Gain (loss) on natural gas derivative instruments (7,492 ) 4,716 Net cash received on settlements of oil derivative instruments (18,766 ) (22,413 ) Net cash received on settlements of natural gas derivative instruments (15,152 ) (11,742 ) Net change in fair value of commodity derivative instruments (54,025 ) (33,135 ) Ending fair value of commodity derivative instruments $ 10,509 $ 4,336
Oil and Natural Gas
Derivative [Line Items]
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of June 30, 2016: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swap Contracts: 2016 Second Quarter 183,000 $ 53.46 $ 33.60 $ 61.96 Third Quarter 525,000 54.62 34.41 62.53 Fourth Quarter 478,000 56.26 36.31 63.07 2017 First Quarter 364,000 $ 62.69 $ 52.73 $ 63.65 Second Quarter 339,000 54.00 53.49 54.38 The Partnership had the following open derivative contracts for natural gas as of June 30, 2016: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: 2016 Third Quarter 7,320,000 $ 2.96 $ 2.23 $ 3.17 Fourth Quarter 6,570,000 3.12 2.29 3.41 2017 First Quarter 5,660,000 $ 3.44 $ 3.08 $ 3.52 Second Quarter 5,310,000 3.12 2.85 3.18 Third Quarter 4,910,000 2.93 2.90 2.94 Fourth Quarter 4,610,000 3.06 2.92 3.21 The Partnership entered into the following derivative contracts for natural gas subsequent to June 30, 2016: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: 2016 Third Quarter 240,000 $ 2.77 $ 2.77 $ 2.78 Fourth Quarter 360,000 3.00 2.81 3.23 2017 First Quarter 510,000 $ 3.34 $ 3.30 $ 3.38 Second Quarter 510,000 3.05 3.03 3.07 Third Quarter 510,000 3.10 3.08 3.11 Fourth Quarter 410,000 3.17 3.10 3.29

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents information about the Partnership’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, 2016 Financial Assets Commodity derivative instruments $ — $ 15,990 $ — $ (2,545 ) $ 13,445 Financial Liabilities Commodity derivative instruments — 5,481 — (2,545 ) 2,936 As of December 31, 2015 Financial Assets Commodity derivative instruments $ — $ 64,534 $ — $ — $ 64,534 Financial Liabilities Commodity derivative instruments — — — — —
Schedule of Assets Measured at Fair Value on a Nonrecurring Basis	The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value 1 Impairment (In thousands) June 30, 2016 Impaired oil and natural gas properties $ — $ — $ 543 $ 1,222 $ 679 March 31, 2016 Impaired oil and natural gas properties $ — $ — $ 2,499 $ 8,595 $ 6,096 June 30, 2015 Impaired oil and natural gas properties $ — $ — $ 71,845 $ 190,207 $ 118,362 March 31, 2015 Impaired oil and natural gas properties $ — $ — $ 17,826 $ 31,293 $ 13,467 1 Amount represents net book value at the date of assessment.

Credit Facility (Tables)

Credit Facility (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Borrowing Base Utilization	Borrowings under the Senior Line of Credit bear interest at LIBOR plus a margin between 1.50% and 2.50%, or the Prime rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan, as detailed in the table below. Borrowing Base Utilization Borrowing type <25% ≥25% <50% ≥ 50% <75% ≥75% <90% ≥90% Eurodollar Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % Base Rate Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 %

Incentive Compensation (Tables)

Incentive Compensation (Tables)	6 Months Ended
	Jun. 30, 2016
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 months and six months ended June 30, 2016 and 2015, respectively. Three Months Ended June 30, Six Months Ended June 30, Incentive compensation expense 2016 2015 2016 2015 (In thousands) (In thousands) Cash—long-term incentive plan $ 560 $ 4,029 $ 2,410 $ 7,480 Equity-based compensation—restricted common and subordinated units 3,190 2,668 5,933 3,950 Equity-based compensation—restricted performance units 5,426 1,260 8,039 1,260 Board of Directors incentive plan 476 1,671 957 2,152 Total incentive compensation expense $ 9,652 $ 9,628 $ 17,339 $ 14,842

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	6 Months Ended
	Jun. 30, 2016
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: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (In thousands, except per unit amounts) (In thousands, except per unit amounts) Net loss $ (20,810 ) $ (122,766 ) $ (10,061 ) $ (105,467 ) Net (income) loss attributable to Predecessor — 16,849 — (450 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 9 140 7 140 Distributions on redeemable preferred units subsequent to initial public offering (1,310 ) (1,810 ) (3,114 ) (1,810 ) Net loss attributable to the general partner and common and subordinated units subsequent to initial public offering $ (22,111 ) $ (107,587 ) $ (13,168 ) $ (107,587 ) Allocation of net income (loss) subsequent to initial public offering attributable to: General partner interest $ — $ — $ — $ — Common units (7,445 ) (54,109 ) 862 (54,109 ) Subordinated units (14,666 ) (53,478 ) (14,030 ) (53,478 ) $ (22,111 ) $ (107,587 ) $ (13,168 ) $ (107,587 ) Net income (loss) attributable to limited partners per common and subordinated units: Per common unit (basic) $ (0.08 ) $ (0.56 ) $ 0.01 $ (0.56 ) Weighted average common units outstanding (basic) 96,356 96,178 96,418 96,178 Per subordinated unit (basic) $ (0.15 ) $ (0.56 ) $ (0.15 ) $ (0.56 ) Weighted average subordinated units outstanding (basic) 95,189 95,057 95,092 95,057 Per common unit (diluted) $ (0.08 ) $ (0.56 ) $ 0.01 $ (0.56 ) Weighted average common units outstanding (diluted) 96,418 96,178 96,481 96,178 Per subordinated unit (diluted) $ (0.15 ) $ (0.56 ) $ (0.15 ) $ (0.56 ) Weighted average subordinated units outstanding (diluted) 95,092 95,057 95,092 95,057

Business and Basis of Present27

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions	May 06, 2015USD ($)$ / sharesshares	Jun. 30, 2016StatesBasinsshares
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		61
Common Units
Limited Partners Capital Account [Line Items]
Units exchanged in merger	72,574,715
Capital units converted upon merger		184,000
Common Units | Predecessor
Limited Partners Capital Account [Line Items]
Units conversion ratio as part of merger	1294.65%
Units conversion ratio split up as part of merger	43.29%
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
Subordinated Units
Limited Partners Capital Account [Line Items]
Units exchanged in merger	95,057,312
Capital units converted upon merger		241,000
Subordinated Units | Predecessor
Limited Partners Capital Account [Line Items]
Units conversion ratio as part of merger	1294.65%
Units conversion ratio split up as part of merger	56.71%
Preferred Units | Predecessor
Limited Partners Capital Account [Line Items]
Capital units converted upon merger	117,963
Units conversion ratio as part of merger	100.00%

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations			$ 10,585
Liabilities incurred			172
Liabilities settled			(127)
Accretion expense	$ 200	$ 269	474	$ 540
Revisions			136
Ending asset retirement obligations	$ 11,240		$ 11,240

Acquisitions - Additional Infor

Acquisitions - Additional Information (Details) - USD ($) $ in Thousands	Jun. 17, 2016	Jun. 15, 2016	Jan. 08, 2016
Permian Basin
Business Acquisition [Line Items]
Purchase of mineral and royalty interest			$ 10,000
Weld County, Colorado
Business Acquisition [Line Items]
Purchase of mineral and royalty interest		$ 34,018
Freeport-McMo Ran oil and Gas, Inc
Business Acquisition [Line Items]
Purchase of mineral and royalty interest	$ 87,870

Acquisitions - Schedule of Fair

Acquisitions - Schedule of Fair Values of the Properties Acquired (Details) - USD ($) $ in Thousands	Jun. 17, 2016	Jun. 15, 2016
Weld County, Colorado
Business Acquisition [Line Items]
Proved oil and natural gas properties		$ 18,948
Unproved oil and natural gas properties		14,082
Net working capital		1,038
Asset retirement obligations		(50)
Purchase price allocation		$ 34,018
Freeport-McMo Ran oil and Gas, Inc
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 20,637
Unproved oil and natural gas properties	65,745
Net working capital	1,488
Purchase price allocation	$ 87,870

Derivatives and Financial Ins31

Derivatives and Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	$ 15,990	$ 64,534
Effect of Counterparty Netting, Assets	(2,545)
Net Carrying Value on Balance Sheet, Assets	13,445	64,534
Gross Fair Value, Liabilities	5,481
Effect of Counterparty Netting, Liabilities	(2,545)
Net Carrying Value on Balance Sheet, Liabilities	2,936
Commodity Derivative Assets, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	15,778	48,260
Effect of Counterparty Netting, Assets	(2,366)
Net Carrying Value on Balance Sheet, Assets	13,412	48,260
Deferred Charges and Other Long-term Assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	212	16,274
Effect of Counterparty Netting, Assets	(179)
Net Carrying Value on Balance Sheet, Assets	33	$ 16,274
Commodity Derivative Liabilities, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	4,201
Effect of Counterparty Netting, Liabilities	(2,366)
Net Carrying Value on Balance Sheet, Liabilities	1,835
Commodity Derivative Liabilities, Long-term
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	1,280
Effect of Counterparty Netting, Liabilities	(179)
Net Carrying Value on Balance Sheet, Liabilities	$ 1,101

Derivatives and Financial Ins32

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative [Line Items]
Gain (loss) on commodity derivative instruments	$ (30,733)	$ (18,627)	$ (20,107)	$ 1,020
Net cash received on settlements of derivative instruments			(33,918)	(34,155)
Not Designated as Hedging Instrument
Derivative [Line Items]
Beginning fair value of commodity derivative instruments			64,534	37,471
Net change in fair value of commodity derivative instruments			(54,025)	(33,135)
Ending fair value of commodity derivative instruments	$ 10,509	$ 4,336	10,509	4,336
Oil | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments			(12,615)	(3,696)
Net cash received on settlements of derivative instruments			(18,766)	(22,413)
Natural Gas | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments			(7,492)	4,716
Net cash received on settlements of derivative instruments			$ (15,152)	$ (11,742)

Derivatives and Financial Ins33

Derivatives and Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument - Swap	Aug. 09, 2016MMBTU$ / MMBTU	Jun. 30, 2016MMBTU$ / bbl$ / MMBTUbbl
Oil | Swap Contract of Q2 2016
Derivative [Line Items]
Derivative Contract, Volume | bbl		183,000
Derivative Contract, Weighted Average Price | $ / bbl		53.46
Derivative Contract, Price Range Low | $ / bbl		33.60
Derivative Contract, Price Range High | $ / bbl		61.96
Oil | Swap Contract of Q3 2016
Derivative [Line Items]
Derivative Contract, Volume | bbl		525,000
Derivative Contract, Weighted Average Price | $ / bbl		54.62
Derivative Contract, Price Range Low | $ / bbl		34.41
Derivative Contract, Price Range High | $ / bbl		62.53
Oil | Swap Contract of Q4 2016
Derivative [Line Items]
Derivative Contract, Volume | bbl		478,000
Derivative Contract, Weighted Average Price | $ / bbl		56.26
Derivative Contract, Price Range Low | $ / bbl		36.31
Derivative Contract, Price Range High | $ / bbl		63.07
Oil | Swap Contract of Q1 2017
Derivative [Line Items]
Derivative Contract, Volume | bbl		364,000
Derivative Contract, Weighted Average Price | $ / bbl		62.69
Derivative Contract, Price Range Low | $ / bbl		52.73
Derivative Contract, Price Range High | $ / bbl		63.65
Oil | Swap Contract of Q2 2017
Derivative [Line Items]
Derivative Contract, Volume | bbl		339,000
Derivative Contract, Weighted Average Price | $ / bbl		54
Derivative Contract, Price Range Low | $ / bbl		53.49
Derivative Contract, Price Range High | $ / bbl		54.38
Natural Gas | Swap Contract of Q3 2016
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		7,320,000
Derivative Contract, Weighted Average Price		2.96
Derivative Contract, Price Range Low		2.23
Derivative Contract, Price Range High		3.17
Natural Gas | Swap Contract of Q3 2016 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	240,000
Derivative Contract, Weighted Average Price	2.77
Derivative Contract, Price Range Low	2.77
Derivative Contract, Price Range High	2.78
Natural Gas | Swap Contract of Q4 2016
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		6,570,000
Derivative Contract, Weighted Average Price		3.12
Derivative Contract, Price Range Low		2.29
Derivative Contract, Price Range High		3.41
Natural Gas | Swap Contract of Q4 2016 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	360,000
Derivative Contract, Weighted Average Price	3
Derivative Contract, Price Range Low	2.81
Derivative Contract, Price Range High	3.23
Natural Gas | Swap Contract of Q1 2017
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		5,660,000
Derivative Contract, Weighted Average Price		3.44
Derivative Contract, Price Range Low		3.08
Derivative Contract, Price Range High		3.52
Natural Gas | Swap Contract of Q1 2017 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	510,000
Derivative Contract, Weighted Average Price	3.34
Derivative Contract, Price Range Low	3.30
Derivative Contract, Price Range High	3.38
Natural Gas | Swap Contract of Q2 2017
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		5,310,000
Derivative Contract, Weighted Average Price		3.12
Derivative Contract, Price Range Low		2.85
Derivative Contract, Price Range High		3.18
Natural Gas | Swap Contract of Q2 2017 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	510,000
Derivative Contract, Weighted Average Price	3.05
Derivative Contract, Price Range Low	3.03
Derivative Contract, Price Range High	3.07
Natural Gas | Swap Contract of Q3 2017
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		4,910,000
Derivative Contract, Weighted Average Price		2.93
Derivative Contract, Price Range Low		2.90
Derivative Contract, Price Range High		2.94
Natural Gas | Swap Contract of Q3 2017 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	510,000
Derivative Contract, Weighted Average Price	3.10
Derivative Contract, Price Range Low	3.08
Derivative Contract, Price Range High	3.11
Natural Gas | Swap Contract of Q4 2017
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		4,610,000
Derivative Contract, Weighted Average Price		3.06
Derivative Contract, Price Range Low		2.92
Derivative Contract, Price Range High		3.21
Natural Gas | Swap Contract of Q4 2017 | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	410,000
Derivative Contract, Weighted Average Price	3.17
Derivative Contract, Price Range Low	3.10
Derivative Contract, Price Range High	3.29

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value, assets transfer between the three fair value hierarchy levels	$ 0	$ 0
Fair value, liabilities transfer between the three fair value hierarchy levels	$ 0	$ 0

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, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	$ 15,990	$ 64,534
Effect of Counterparty Netting, Assets	(2,545)
Net Carrying Value on Balance Sheet, Assets	13,445	64,534
Gross Fair Value, Liabilities	5,481
Effect of Counterparty Netting, Liabilities	(2,545)
Net Carrying Value on Balance Sheet, Liabilities	2,936
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of Counterparty Netting, Assets	(2,545)
Net Carrying Value on Balance Sheet, Assets	13,445	64,534
Effect of Counterparty Netting, Liabilities	(2,545)
Net Carrying Value on Balance Sheet, Liabilities	2,936
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	15,990	$ 64,534
Gross Fair Value, Liabilities	$ 5,481

Fair Value Measurements - Sch36

Fair Value Measurements - Schedule of Assets Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Impairment	$ 679		$ 118,362		$ 6,775	$ 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	1,222	$ 8,595	190,207	$ 31,293	1,222	190,207
Impaired oil and natural gas properties, Impairment	679	6,096	118,362	13,467
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	$ 543	$ 2,499	$ 71,845	$ 17,826	$ 543	$ 71,845

Credit Facility - Additional In

Credit Facility - Additional Information (Details) - USD ($)	6 Months Ended
	Jun. 30, 2016	Apr. 15, 2016	Apr. 14, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Credit facility	$ 285,000,000			$ 66,000,000
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		$ 450,000,000	$ 550,000,000
Line of credit amendment date	Oct. 28, 2015
Line of credit facility, earliest expiration date	Feb. 3, 2017
Line of credit facility, latest expiration date	Feb. 4, 2019
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	2.45%			1.92%
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 facility	$ 285,000,000			$ 66,000,000
Line of credit, unused portion of current borrowing base	$ 165,000,000			$ 484,000,000
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%
Senior Line of Credit | Minimum
Line Of Credit Facility [Line Items]
Line of credit, current ratio	100.00%
Senior Line of Credit | Minimum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%
Senior Line of Credit | Minimum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Line of credit, interest rate	0.50%
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 | Maximum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Line of credit, interest rate	2.50%
Senior Line of Credit | Maximum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%

Credit Facility - Borrowing Bas

Credit Facility - Borrowing Base Utilization (Details)	6 Months Ended
	Jun. 30, 2016
Eurodollar Margin | Borrowing Base Utilization Less Than25 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%
Eurodollar Margin | Borrowing Base Utilization Percentage Greater Than Equal To25 Percent But Less Than50 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.75%
Eurodollar Margin | Borrowing Base Utilization Percentage Greater Than Equal To50 Percent But Less Than75 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	2.00%
Eurodollar Margin | Borrowing Base Utilization Percentage Greater Than Equal To75 Percent But Less Than90 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	2.25%
Eurodollar Margin | Borrowing Base Utilization Range Equal To Above90 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	2.50%
Base Rate Margin | Borrowing Base Utilization Less Than25 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	0.50%
Base Rate Margin | Borrowing Base Utilization Percentage Greater Than Equal To25 Percent But Less Than50 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	0.75%
Base Rate Margin | Borrowing Base Utilization Percentage Greater Than Equal To50 Percent But Less Than75 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.00%
Base Rate Margin | Borrowing Base Utilization Percentage Greater Than Equal To75 Percent But Less Than90 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.25%
Base Rate Margin | Borrowing Base Utilization Range Equal To Above90 Percent
Line Of Credit Facility [Line Items]
Line of credit, interest rate	1.50%

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	Jun. 30, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
Provision for remediation costs	$ 0

Incentive Compensation - Additi

Incentive Compensation - Additional Information (Details) $ in Millions	Feb. 19, 2016Timeshares	Jan. 12, 2016shares	Jun. 30, 2016USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash settled liabilities reclassified to equity settled liabilities | $			$ 10.1
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units	717,654
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units	717,654
Target number of common units, Minimum | Time	0
Target number of common units, Maximum | Time	2
Common Units | Non-employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested		12,368

Incentive Compensation - Summar

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 560	$ 4,029	$ 2,410	$ 7,480
Total incentive compensation expense	9,652	9,628	17,339	14,842
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	3,190	2,668	5,933	3,950
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	5,426	1,260	8,039	1,260
Board of Directors | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 476	$ 1,671	$ 957	$ 2,152

Redeemable Preferred Units - Ad

Redeemable Preferred Units - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Class Of Stock [Line Items]
Preferred units, outstanding value	$ 54,001	$ 79,162
Preferred Units
Class Of Stock [Line Items]
Partners' equity, preferred units, outstanding	52,691	77,216
Preferred units, outstanding value	$ 54,000	$ 79,200
Accrued distributions	$ 1,300	$ 1,900
Preferred units distribution rate	10.00%
Adjusted conversion price	$ 14.2683
Preferred units, redemption terms	The preferred unitholders can elect to have the Partnership redeem up to 25% per year of their initial balance of preferred units at face value, plus any accrued and unpaid distributions, as of December 31 of each year from 2014 to 2017. The Partnership 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 as of each December 31. Any amount of a given year’s 25% of preferred units not redeemed as of December 31 shall automatically convert to common and subordinated units in 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
Preferred units redeemed, units	18,461
Preferred units redeemed, value	$ 19,000
Number of preferred units converted	6,064	39,240
Conversion of preferred units to common units	$ 6,100	$ 39,200
Common Units
Class Of Stock [Line Items]
Adjusted conversion rate	30.3431
Conversion of preferred units	184,006	1,190,664
Subordinated Units
Class Of Stock [Line Items]
Adjusted conversion rate	39.7427
Conversion of preferred units	240,986	1,559,502

Earnings Per Unit - Additional

Earnings Per Unit - Additional Information (Details)	6 Months Ended
	Jun. 30, 2016shares
Restricted Performance Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	125,487
Common Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	1,600,000
Subordinated Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	2,100,000

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share Basic [Line Items]
Net income (loss)	$ (20,810)	$ (122,766)	$ (10,061)	$ (105,467)
Net loss attributable to noncontrolling interests subsequent to initial public offering	9	140	7	140
Distributions on redeemable preferred units subsequent to initial public offering	(1,310)	(1,810)	(3,114)	(1,810)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(22,111)	(107,587)	(13,168)	(107,587)
Allocation of net income (loss) subsequent to initial public offering attributable to:
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(22,111)	(107,587)	(13,168)	(107,587)
Common Units
Allocation of net income (loss) subsequent to initial public offering attributable to:
Allocation of net income (loss)	$ (7,445)	$ (54,109)	$ 862	$ (54,109)
Net income (loss) attributable to limited partners per common and subordinated units:
Per unit (basic)	$ (0.08)	$ (0.56)	$ 0.01	$ (0.56)
Weighted average units outstanding (basic)	96,356	96,178	96,418	96,178
Per unit (diluted)	$ (0.08)	$ (0.56)	$ 0.01	$ (0.56)
Weighted average units outstanding (diluted)	96,418	96,178	96,481	96,178
Subordinated Units
Allocation of net income (loss) subsequent to initial public offering attributable to:
Allocation of net income (loss)	$ (14,666)	$ (53,478)	$ (14,030)	$ (53,478)
Net income (loss) attributable to limited partners per common and subordinated units:
Per unit (basic)	$ (0.15)	$ (0.56)	$ (0.15)	$ (0.56)
Weighted average units outstanding (basic)	95,189	95,057	95,092	95,057
Per unit (diluted)	$ (0.15)	$ (0.56)	$ (0.15)	$ (0.56)
Weighted average units outstanding (diluted)	95,092	95,057	95,092	95,057
Predecessor
Earnings Per Share Basic [Line Items]
Net income (loss)		$ 16,849		$ (450)

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Subsequent Event	Aug. 08, 2016$ / shares
Subsequent Event [Line Items]
Distribution declaration date	Aug. 8, 2016
Distribution date of record	Aug. 18, 2016
Distribution date	Aug. 25, 2016
Common Units
Subsequent Event [Line Items]
Quarterly cash distribution declared	$ 0.2875
Subordinated Units
Subsequent Event [Line Items]
Quarterly cash distribution declared	$ 0.18375