Black Stone Minerals (BSM) 10-K 8 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 04, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	BSM
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Central Index Key	1,621,434
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 1,240,495,410
Common Units
Document Information [Line Items]
Entity Partnership Units Outstanding		96,965,879
Subordinate Units
Document Information [Line Items]
Entity Partnership Units Outstanding		95,002,347
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding		77,216

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 13,233	$ 14,803
Accounts receivable	41,246	74,092
Commodity derivative assets	48,260	37,471
Prepaid expenses and other current assets	856	8,538
TOTAL CURRENT ASSETS	103,595	134,904
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $524,563 and $626,376 at December 31, 2015 and 2014, respectively	2,482,211	2,379,543
Accumulated depreciation, depletion, amortization, and impairment	(1,543,796)	(1,191,861)
Oil and natural gas properties, net	938,415	1,187,682
Other property and equipment, net of accumulated depreciation of $14,660 and $12,994 at December 31, 2015 and 2014, respectively	179	1,664
NET PROPERTY AND EQUIPMENT	938,594	1,189,346
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	19,247	2,532
TOTAL ASSETS	1,061,436	1,326,782
CURRENT LIABILITIES
Accounts payable	5,036	5,434
Accrued liabilities	58,003	40,233
TOTAL CURRENT LIABILITIES	63,039	98,572
LONG-TERM LIABILITIES
Credit facility	66,000	394,000
Accrued incentive compensation	7,902	6,530
Deferred revenue	3,257	3,917
Asset retirement obligations	10,585	9,381
TOTAL LIABILITIES	$ 150,783	$ 512,400
COMMITMENTS AND CONTINGENCIES (Note 12)
MEZZANINE EQUITY
Partners' equity - redeemable preferred units, 77 and 157 units outstanding at December 31, 2015 and 2014, respectively	$ 79,162	$ 161,165
EQUITY
Noncontrolling interests	1,144
TOTAL EQUITY	831,491	653,217
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	1,061,436	1,326,782
Predecessor
CURRENT LIABILITIES
Accrued distribution payable to Predecessor unitholders		52,905
EQUITY
TOTAL EQUITY		653,217
Common Units
EQUITY
Partners' equity - units	574,648
Common Units | Predecessor
EQUITY
Partners' equity - limited partner units		$ 653,217
Subordinate Units
EQUITY
Partners' equity - units	$ 255,699

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and natural gas properties, unproved property costs	$ 524,563	$ 626,376
Other property and equipment accumulated depreciation and amortization	$ 14,660	$ 12,994
Preferred Units
Partners' equity, preferred units, outstanding	77,216	157,203
Common Units
Partners' equity - units, outstanding	96,162,000	0
Common Units | Predecessor
Partners' equity, limited partner units, outstanding	0	164,484,000
Partners' equity - units, outstanding		164,484,000
Subordinate Units
Partners' equity - units, outstanding	95,057,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUE
Oil and condensate sales	$ 163,538	$ 257,390	$ 252,742
Natural gas and natural gas liquids sales	116,018	207,456	184,868
Gain (loss) on commodity derivative instruments	90,288	37,336	(5,860)
Lease bonus and other income	23,080	46,139	31,809
TOTAL REVENUE	392,924	548,321	463,559
OPERATING (INCOME) EXPENSE
Lease operating expense	21,583	21,233	21,142
Production costs and ad valorem taxes	35,767	49,575	42,813
Exploration expense	2,592	631	174
Depreciation, depletion and amortization	104,298	111,962	102,442
Impairment of oil and natural gas properties	249,569	117,930	57,109
General and administrative	77,175	62,765	59,501
Accretion of asset retirement obligations	1,075	1,060	588
(Gain) loss on sale of assets, net	(4,873)	32	(18)
Other expense	1,593	1,424
TOTAL OPERATING EXPENSE	488,779	366,612	283,751
INCOME (LOSS) FROM OPERATIONS	(95,855)	181,709	179,808
OTHER INCOME (EXPENSE)
Interest and investment income	58	28	90
Interest expense	(6,418)	(13,509)	(11,342)
Other income	910	959	407
TOTAL OTHER EXPENSE	(5,450)	(12,522)	(10,845)
NET INCOME (LOSS)	(101,305)	169,187	168,963
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING	1,260
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(7,522)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(108,017)
ALLOCATION OF 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	(108,017)
Predecessor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	(450)	$ (169,187)	$ (168,963)
Common Units
ALLOCATION OF LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of loss	$ (54,326)
NET LOSS ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic)	$ (0.56)
Per unit (diluted)	$ (0.56)
Weighted average units outstanding (basic and diluted)	96,182
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit	$ 0.4240
Subordinate Units
ALLOCATION OF LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of loss	$ (53,691)
NET LOSS ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic)	$ (0.56)
Per unit (diluted)	$ (0.56)
Weighted average units outstanding (basic and diluted)	95,057
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit	$ 0.4240

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - 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, 2012	$ 326,663
Beginning balance at Dec. 31, 2012	326,663
Beginning balance, units (Predecessor) at Dec. 31, 2012		93,498
Contributions—cash | Predecessor	412,233
Contributions—cash	412,233
Contributions—cash units | Predecessor		18,801
Contributions—limited partner interests | Predecessor	1,019,340
Contributions—limited partner interests	1,019,340
Contributions—limited partner interests, units | Predecessor		46,481
Issuance of Predecessor units for acquisition of oil and natural gas properties | Predecessor	227,119
Issuance of Predecessor units for acquisition of oil and natural gas properties	227,119
Issuance of Predecessor units for acquisition of oil and natural gas properties, units | Predecessor		10,359
Repurchase of Predecessor units | Predecessor	(118,108)
Repurchase of Predecessor units	(118,108)
Repurchase of Predecessor units, units | Predecessor		(5,410)
Restricted Predecessor units granted, net of forfeitures | Predecessor		404
Equity-based compensation | Predecessor	6,782
Equity-based compensation	6,782
Distributions to Predecessor unitholders and noncontrolling interests | Predecessor	(235,078)
Distributions to Predecessor unitholders and noncontrolling interests	(235,078)
Distributions—property | Predecessor	(19,029)
Distributions—property	(19,029)
Purchases of Predecessor noncontrolling interests | Predecessor	(37,400)
Purchases of Predecessor noncontrolling interests	(37,400)
Exchange of Predecessor noncontrolling interests | Predecessor	(1,019,340)
Exchange of Predecessor noncontrolling interests	(1,019,340)
Net income (loss) | Predecessor	168,963
Net income (loss)	168,963
Distributions on Predecessor redeemable preferred units | Predecessor	(15,742)
Distributions on Predecessor redeemable preferred units	(15,742)
Ending balance (Predecessor) at Dec. 31, 2013	716,403
Ending balance at Dec. 31, 2013	716,403
Ending balance, units (Predecessor) at Dec. 31, 2013		164,133
Conversion of Predecessor redeemable preferred units | Predecessor	221
Conversion of Predecessor redeemable preferred units	221
Conversion of Predecessor preferred units, units | Predecessor		15
Issuance of Predecessor units for acquisition of oil and natural gas properties | Predecessor	2,258
Issuance of Predecessor units for acquisition of oil and natural gas properties	2,258
Issuance of Predecessor units for acquisition of oil and natural gas properties, units | Predecessor		104
Repurchase of Predecessor units | Predecessor	(5,199)
Repurchase of Predecessor units	(5,199)
Repurchase of Predecessor units, units | Predecessor		(239)
Restricted Predecessor units granted, net of forfeitures | Predecessor		471
Equity-based compensation | Predecessor	11,340
Equity-based compensation	11,340
Distributions to Predecessor unitholders and noncontrolling interests | Predecessor	(225,273)
Distributions to Predecessor unitholders and noncontrolling interests	(225,273)
Net income (loss) | Predecessor	169,187
Net income (loss)	169,187
Distributions on Predecessor redeemable preferred units | Predecessor	(15,720)
Distributions on Predecessor redeemable preferred units	(15,720)
Ending balance (Predecessor) at Dec. 31, 2014	653,217
Ending balance at Dec. 31, 2014	653,217
Ending balance, units (Predecessor) at Dec. 31, 2014		164,484
Ending balance, units at Dec. 31, 2014		0	0
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
Repurchase of Predecessor units | Predecessor	(3,015)
Repurchase of Predecessor units	(3,015)
Repurchase of Predecessor units, units | Predecessor		(164)
Restricted Predecessor units granted, net of forfeitures | Predecessor		562
Restricted Predecessor units granted, net of forfeitures		1,087
Equity-based compensation	18,000			$ 14,181	$ 3,819
Distributions to Predecessor unitholders and noncontrolling interests | Predecessor	(73,205)
Distributions to Predecessor unitholders and noncontrolling interests	(73,205)
Net income (loss) | Predecessor	450
Net income (loss)	(101,755)			(50,543)	(49,952)	$ (1,260)
Distributions on Predecessor redeemable preferred units | Predecessor	(4,040)
Distributions on Predecessor redeemable preferred units	(4,040)
Ending balance at Dec. 31, 2015	831,491			574,648	255,699	1,144
Ending balance, units at Dec. 31, 2015		96,162	95,057
Allocation of Predecessor units and equity | Predecessor	(612,647)
Allocation of Predecessor units and equity				264,235	345,875	2,537
Allocation of Predecessor units and equity, units | Predecessor		(167,632)
Allocation of Predecessor units and equity, 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
Distributions	(81,220)			(40,783)	(40,304)	$ (133)
Charges to partners' equity for accrued distribution equivalent rights	(159)			(159)
Distributions on redeemable preferred units	$ (7,522)			$ (3,783)	$ (3,739)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (101,305)	$ 169,187	$ 168,963
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	104,298	111,962	102,442
Impairment of oil and natural gas properties	249,569	117,930	57,109
Accretion of asset retirement obligations	1,075	1,060	588
Amortization of deferred charges	935	965	968
Gain (loss) on commodity derivative instruments	(90,288)	(37,336)	5,860
Net cash received (paid) on settlement of commodity derivative instruments	63,225	(1,947)	1,490
Equity-based compensation	18,000	11,340	6,782
(Gain) loss on sale of assets, net	(4,873)	32	(18)
Changes in operating assets and liabilities:
Accounts receivable	33,586	17,210	(15,046)
Prepaid expenses and other current assets	95	453	(1,256)
Accounts payable and accrued liabilities	11,221	8,003	(7,085)
Deferred revenue	(660)	(2,589)
Settlement of asset retirement obligations	(143)	(145)	(33)
NET CASH PROVIDED BY OPERATING ACTIVITIES	284,735	396,125	320,764
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties	(54,244)	(74,201)	(73,650)
Purchase of other property and equipment	(181)	(827)	(493)
Proceeds from the sale of oil and natural gas properties	25,705	19,470	74
Acquisitions of oil and natural gas properties	(62,278)	(45,552)	(121,562)
NET CASH USED IN INVESTING ACTIVITIES	(90,998)	(101,110)	(195,631)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs	399,087	(7,587)
Net (repayments) borrowings under senior line of credit	(328,000)	(57,000)	134,000
Distributions to noncontrolling interests	(208)
Redemption of redeemable preferred units	(40,747)
Repurchases of Predecessor units	(3,015)	(5,199)	(118,108)
Debt issuance costs	(1,376)		(1,660)
Note receivable-officers		101	101
Repayments of revolving credit facilities			(46,100)
Contributions from Predecessor unitholders			191,611
Purchases of noncontrolling interests			(60,719)
NET CASH USED IN FINANCING ACTIVITIES	(195,307)	(310,335)	(142,311)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(1,570)	(15,320)	(17,178)
CASH AND CASH EQUIVALENTS - beginning of the year	14,803	30,123	47,301
CASH AND CASH EQUIVALENTS - end of the year	13,233	14,803	30,123
SUPPLEMENTAL DISCLOSURE
Interest paid	5,478	12,754	10,344
NON-CASH ACTIVITIES
Conversion of redeemable preferred units	(39,240)	(221)
Accrued distributions payable for redeemable preferred units	(2,016)	(4)	10
Property additions and acquisitions financed through accounts payable and accrued liabilities	21,496	14,130	23,029
Public offering costs capitalized and offset against proceeds from initial public offering	7,587
Asset retirement obligations incurred	272	2,505	164
Accrued distribution equivalent rights	159
Liabilities assumed as consideration for oil and natural gas properties acquired		7,000
Acquisition of oil and natural gas properties financed through issuance of Predecessor units		2,258	227,119
Deferred revenue (settled) assumed through acquisition of oil and natural gas properties		(2,657)	902
Contributions through exchange of noncontrolling interests			1,019,340
Distributions—property			19,029
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	(450)	(169,187)	(168,963)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(126,383)	(224,926)	(225,704)
NON-CASH ACTIVITIES
Accrued Predecessor distributions payable	(53,248)	347	9,374
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(81,087)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (13,578)	$ (15,724)	$ (15,732)

Business and Basis of Presentat

Business and Basis of Presentation	12 Months Ended
	Dec. 31, 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 “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. The Partnership’s assets include mineral interests, nonparticipating royalty interests, and overriding royalty interests. These non-cost-bearing interests are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are 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 U.S. The Partnership also owns non-operated working interests in certain oil and natural gas properties. Basis of presentation 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. 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. Segment reporting

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of estimates The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments, revenue accruals, asset retirement obligation (“ARO”) liabilities, and determination of the fair value of equity-based awards. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in natural gas or oil prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from estimates. Cash and cash equivalents Concentration of credit risk Accounts receivable Derivatives and financial instruments Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. Prepaid expenses and other current assets Oil and natural gas properties The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved leaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs are assessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired. Mineral interests are assessed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessment is performed by comparing carrying values to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties. As exploration and development work progresses and the reserves associated with the Partnership’s properties become proven, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Acquisition costs of proved properties are amortized on the basis of all proved reserves, both developed and undeveloped, and capitalized development costs are amortized on the basis of proved developed reserves. Proved reserves are quantities of oil and natural gas that can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations. DD&A expense related to the Partnership’s producing oil and natural gas properties was $102.7 million, $109.9 million and $100.6 million for the years ended December 31, 2015, 2014, and 2013, respectively. 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. This evaluation is performed on a field-by-field basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a field to the carrying amount to determine recoverability. When the carrying amount of a field 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 proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate. Impairment of proved oil and natural gas properties was $127.8 million, $117.9 million and $57.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. The impairment primarily resulted from declines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties. The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment using management’s assessment of fair value. The factors used to determine fair value are similar to those previously noted for proved properties. Impairment of unproved properties was $121.8 million for the year ended December 31, 2015. There was no impairment of unproved properties for the years ended December 31, 2014 and 2013. Upon the sale of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value is charged to income. On sale or retirement of an individual well, the proceeds are credited to accumulated DD&A. Other property and equipment Repairs and maintenance Accrued distribution payable to Predecessor unitholders Debt issuance costs Asset retirement obligations Revenue recognition The Partnership recognizes oil and natural gas revenue from its interests in producing wells when the associated production is sold. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Partnership, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2015 and 2014. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Other sources of revenue received by the Partnership includes mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to other exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. The Partnership recognizes such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable, and the Partnership has no further obligation to refund the payment. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and the Partnership has no further obligation to refund the payment. Income taxes Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas. Fair value of financial instruments Incentive compensation Liability awards are awards that are expected to be settled in cash on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans. The Partnership may also recognize liability awards as a result of repurchase options given to the recipients participating in certain incentive plans. Compensation expense for unit-based awards subsequent to the Partnership’s initial public offering is measured by the price of the unit at the measurement date, which is generally the date of grant, and is recognized in general and administrative expense over the requisite service period. Prior to the initial public offering, the Predecessor was privately held and determining the fair value required the Predecessor to make complex and subjective judgments. The Board determined the fair value of the equity-based awards’ unit price prior to the Partnership’s initial public offering by considering various objective and subjective factors, along with input from management. To determine the fair value of the Predecessor, the Predecessor considered information provided by third-party consultants and relied on generally accepted valuation techniques, which included, but were not limited to, the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. These methods were dependent upon various assumptions to develop the estimates in the Predecessor’s operating results, commodity prices, and market-based discount rates. The Predecessor also considered publicly available information on comparable public companies and the Predecessor’s historical transactions and performance in making these estimates. The Predecessor’s limited partnership agreement contained an annual repurchase obligation of 1% of the outstanding units. An annual valuation of the Predecessor was required to establish a value basis for the repurchase obligation. The Predecessor utilized the same valuation for repurchases and issuances of equity, if any, and as the basis for calculating the fair value of its equity awards under its long-term incentive plans. 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 In November 2014, the FASB issued an accounting standards update that clarifies how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Partnership adopted this guidance on January 1, 2016, and there was no material impact to the Partnership’s consolidated financial statements and related disclosures. 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 Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s consolidated financial statements and related disclosures. In September 2015, the FASB issued an accounting standards update that requires that adjustments to provisional amounts identified during the measurement period of a business combination be recognized in the reporting period in which those adjustments are determined, including the effect on earnings, if any, calculated as if the accounting had been completed at the acquisition date. This eliminates the previous requirement to retrospectively account for such adjustments. The new standard also requires additional disclosures related to the income statement effects of adjustments to provisional amounts identified during the measurement period. The guidance is effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s consolidated financial statements and related disclosures.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	NOTE 3—ASSET RETIREMENT OBLIGATIONS The ARO liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s 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 the 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 Partnership’s ARO liability: For the year ended December 31, 2015 2014 (In thousands) Beginning asset retirement obligations $ 9,381 $ 5,961 Liabilities incurred 272 167 Liabilities settled (143 ) (145 ) Accretion expense 1,075 1,060 Revisions in estimated costs — 2,338 Ending asset retirement obligations $ 10,585 $ 9,381

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
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. The Partnership acquired mineral and royalty interests in the Permian Basin throughout 2015. Separate transactions were closed on June 30, 2015 ($14.4 million), July 15, 2015 ($7.8 million), August 5, 2015 ($20.3 million), August 21, 2015 ($5.8 million), and September 22, 2015 ($3.4 million). The Partnership acquired acreage in the Eagle Ford Shale play through two transactions: mineral and royalty interests in June of 2015 for $0.5 million and mineral and royalty and non-operated working interests on September 24, 2015 for $9.2 million. On June 2, 2015, the Partnership also acquired overriding royalty interests in the Utica Shale and Marcellus plays for $1.8 million. During 2014, the Predecessor acquired mineral and royalty interests in the Permian Basin for $16.0 million and the Eagle Ford Shale play for $11.9 million. The Predecessor also acquired non-operated working interests in the Haynesville play for $24.6 million and mineral and royalty interests and non-operated working interests in various states for $2.3 million through the issuance of Predecessor units. In 2004, the Predecessor and third-party investors acquired an interest in the producing and non-producing oil and natural gas properties of Pure Partners, L.P. and Pure Resources, L.P. (“Pure”). As of December 31, 2012, the Predecessor owned 86.4% of the oil and natural gas properties of Pure. Third-party investors owned the remaining 13.6% of the oil and natural gas properties. Effective January 1, 2013, the Predecessor purchased the remaining ownership interest in the Pure oil and natural gas properties through the issuance of $227.1 million of Predecessor units. The fair value of the assets acquired was determined based on discounted cash flows, including assumptions as to the estimated ultimate recovery of oil and natural gas reserves, expectations for timing of future development and operating costs, and risk-adjusted discount rates. The following table summarizes the fair values assigned to the assets acquired as of January 1, 2013: (In thousands) Proved oil and natural gas properties $ 51,573 Unproved oil and natural gas properties 169,150 Net working capital 6,396 Total net assets acquired $ 227,119

Derivatives and Financial Instr

Derivatives and Financial Instruments	12 Months Ended
	Dec. 31, 2015
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 given commodity price risk associated with its operations, the Partnership uses 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 Partnership does not enter into derivative instruments for speculative purposes. 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. 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 Partnership if the settlement price for any settlement period is below the exercise price of the purchased put. The Partnership 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. 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 December 31, 2015 and 2014, respectively. 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 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 $ — $ — $ — As of December 31, 2014 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 $ 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 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 year ended December 31, Derivatives not designated as hedging instruments 2015 2014 2013 (In thousands) Beginning fair value of commodity derivative instruments $ 37,471 $ (1,812 ) $ 5,538 Gain on oil derivative instruments 57,681 27,548 (3,469 ) Gain on natural gas derivative instruments 32,607 9,788 (2,391 ) Net cash received on settlements of oil derivative instruments (41,786 ) (46 ) 505 Net cash (received) paid on settlements of natural gas derivative instruments (21,439 ) 1,993 (1,995 ) Net change in fair value of commodity derivative instruments 27,063 39,283 (7,350 ) Ending fair value of commodity derivative instruments $ 64,534 $ 37,471 $ (1,812 ) The Partnership had the following open derivative contracts for oil as of December 31, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Collar Contracts: Q4 2015 Call Options 10,000 $ 102.00 $ 102.00 $ 102.00 Put Options 10,000 85.00 85.00 85.00 Oil Swap Contracts: Q4 2015 173,000 59.67 48.65 61.71 Q1 2016 502,000 55.88 48.54 61.34 Q2 2016 455,000 57.30 50.14 61.96 Q3 2016 424,000 58.38 51.27 62.53 Q4 2016 398,000 59.43 52.40 63.07 FY 2017 703,000 58.50 52.73 63.65 The Partnership had the following open derivative contracts for natural gas as of December 31, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 6,780,000 $ 3.26 $ 3.16 $ 3.38 Q2 2016 6,240,000 3.07 3.00 3.14 Q3 2016 5,830,000 3.13 3.06 3.17 Q4 2016 5,400,000 3.25 3.10 3.41 FY 2017 9,650,000 3.33 3.14 3.52 The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swap Contracts: Q1 2016 28,000 $ 29.56 $ 29.07 $ 29.79 Q2 2016 81,000 32.60 31.25 33.93 Q3 2016 65,000 35.20 34.41 36.09 Q4 2016 50,000 37.00 36.31 37.73 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 340,000 $ 1.98 $ 1.96 $ 1.99 Q2 2016 970,000 2.10 2.03 2.19 Q3 2016 780,000 2.26 2.23 2.28 Q4 2016 550,000 2.42 2.29 2.61

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2015
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 years ended December 31, 2015 and 2014. 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 December 31, 2015 Financial Assets Commodity derivative instruments $ — $ 64,534 $ — $ — $ 64,534 Financial Liabilities Commodity derivative instruments — — — — — 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 Non-Recurring 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, measurements of oil and natural gas property impairments, and the initial recognition of ARO, for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these measurements as Level 3. 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 measuring 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. 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 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 for the years ended December 31, 2015 and 2014. The following table presents information about the Partnership’s assets measured at fair value on a non-recurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value 1 Impairment (In thousands) Year Ended December 31, 2015 Impaired oil and natural gas properties $ — $ — $ 156,689 $ 406,258 $ 249,569 Year Ended December 31, 2014 Impaired oil and natural gas properties $ — $ — $ 81,864 $ 199,794 $ 117,930 Year Ended December 31, 2013 Impaired oil and natural gas properties $ — $ — $ 56,318 $ 113,427 $ 57,109 1 Amount represents net book value at the date of assessment. The carrying value of all debt as of December 31, 2015 and 2014 approximates 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 7—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 year ended December 31, 2014.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2015
Risks And Uncertainties [Abstract]
Significant Customers	NOTE 8—SIGNIFICANT CUSTOMERS The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. No customer represented 10.0% or more of total revenue for the year ended December 31, 2015. One company, Chesapeake Energy Corporation, represented 10.0% and 10.9% of total revenue for the years ended December 31, 2014 and 2013, respectively. If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests. The loss of any single customer is mitigated by the Partnership’s diversified customer base.

Credit Facilities

Credit Facilities	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Credit Facilities	NOTE 9—CREDIT FACILITIES Senior Line of Credit The Partnership maintains a senior secured revolving credit agreement, as amended, (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 further 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 strip prices. The borrowing base was $700.0 million at December 31, 2014. The Partnership’s semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base to $600.0 million, effective April 10, 2015. Effective October 28, 2015, the borrowing base was further decreased to $550.0 million. 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 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 1.92% and 2.41% as of December 31, 2015 and 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 0.500% 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 Partnership’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 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 December 31, 2015, the Partnership was in compliance with all financial covenants in the Senior Line of Credit. The aggregate principal balance outstanding was $66.0 million and $394.0 million at December 31, 2015 and 2014, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $484.0 million and $306.0 million at December 31, 2015 and 2014, respectively. Refer to Note 1 – Business and Basis of Presentation for a discussion of the use of proceeds from the IPO. BSNR II-B Revolving Credit Facility Black Stone Natural Resources II-B, L.P., a consolidated subsidiary of the Predecessor, obtained a $50.0 million five-year revolving credit facility dated November 9, 2005, as amended, on November 3, 2010, (“BSNR II-B Revolving Credit Facility”) with a financial institution as the administrative agent and the lender. The Predecessor repaid the outstanding principal balance of $19.1 million on March 28, 2013, and the BSNR II-B Revolving Credit Facility was terminated on April 30, 2013. BSNR III-B Revolving Credit Facility Black Stone Natural Resources III-B, L.P., a consolidated subsidiary of the Predecessor, obtained a $100.0 million revolving credit facility dated October 10, 2008 (“BSNR III-B Revolving Credit Facility”), with a financial institution as the administrative agent and the lender. On December 27, 2012, the BSNR III-B Revolving Credit Facility was amended and extended through November 30, 2017. The Predecessor repaid the outstanding principal balance of $27.0 million and terminated the BSNR III-B Revolving Credit Facility on May 15, 2013.

Incentive Compensation

Incentive Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Incentive Compensation	NOTE 10—INCENTIVE COMPENSATION Overview The Board of Directors of the Partnership’s general partner (“the Board”) adopted a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to the Partnership’s common or subordinated units. On May 6, 2015, the Partnership registered 17,420,310 common and subordinated units that are issuable under the 2015 LTIP. 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. Any vesting terms associated with incentive awards will be based on a predetermined schedule as approved by the Board. Incentive compensation expense is included in general and administrative expense on the consolidated statements of operations. The total compensation expense related to the common and subordinated unit grants is measured as the number of units granted that are expected to vest multiplied by the grant-date fair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the award agreements over the requisite service periods (generally equivalent to the vesting period). Cash Awards The Partnership provides cash long-term incentive awards annually for its executive officers and certain other employees. In 2012, the Predecessor adopted a long-term incentive plan that combined both its management and senior management long-term incentive plans (the “2012 LTI Plan”). Under the 2012 LTI Plan, executive officers and certain other members of management are granted fifty percent of their incentive compensation in performance cash awards determined based on achieving specific production and reserves targets as set by the Board. Cash award compensation cliff vests on the third anniversary of the grant date, subject to satisfaction of the applicable performance targets so long as the employee remains employed through the vesting date. Certain other employees are entitled to earn cash bonuses based on service criteria over a four-year requisite service period. Payments are disbursed one-third per year over three years beginning on the first anniversary following December 31 of the service year. On May 6, 2015, cash awards totaling $2.7 million with service-based graded vesting requirements through March 31, 2019 were also granted to certain other employees. Unit Grant Awards The remaining fifty percent of incentive compensation was paid in the form of restricted common units of the Predecessor under the 2012 LTI Plan to executive officers and certain other members of management. Restricted common units of the Predecessor that were outstanding as of the date of the IPO were converted into restricted common and subordinated units of the Partnership in connection with the IPO as set forth in the table below. The converted restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Each converted award vests pursuant to the original vesting schedule applicable to the restricted unit award of the Predecessor. Award recipients have all the rights of a unitholder in the Partnership with respect to the converted restricted units, including the right to receive distributions thereon, if and when distributions are made by the Partnership to its limited partners. For awards granted prior to December 31, 2014, recipients could request that the Partnership, at its discretion, repurchase up to fifty percent of the restricted common units that are scheduled to vest. As a result of the repurchase option, fifty percent of the equity awards to be vested on each vesting date were classified as a liability during the corresponding year prior to the vesting date until a request for the Partnership to repurchase was made by the recipient, or the repurchase option period ended, which was 30 days prior to the vesting date. The liability was measured periodically at fair value. In conjunction with the adoption of the 2015 LTIP, the provision 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 was removed; as such, these awards are no longer classified as liability awards. Non-employee directors of the Partnership’s general partner received compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service. On May 6, 2015, in conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the Partnership’s executive officers, certain other employees, and each of the non-employee directors of the Partnership’s general partner. 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. Additionally, non-employee directors of the Partnership’s general partner received a one-time grant totaling 63,156 fully vested common units. The following table summarizes information about restricted units for the year ended December 31, 2015. Units Weighted-Average Grant-Date Fair Value per Unit Units Predecessor Common Subordinated Predecessor Common Subordinated Unvested at December 31, 2014 668,119 — — $ 20.81 $ — $ — Granted 441,900 1,110,877 — 18.30 18.98 — Vested (329,190 ) (63,156 ) — 20.87 19.00 — Converted 1 (780,829 ) 338,051 442,778 19.36 19.36 19.36 Forfeited — (23,681 ) — — 19.00 — Unvested at December 31, 2015 — 1,362,091 442,778 $ — $ 19.08 $ 19.36 1 Consistent with all outstanding Predecessor units, the Predecessor restricted unit award agreements were converted into common and subordinated units of the Partnership at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units as described in Note 1 – Business and Basis of Presentation. The weighted-average grant-date fair value for unit-based awards was $18.79, $20.73, and $20.78 for the years ended December 31, 2015, 2014, and 2013, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $19.6 million and $4.7 million, respectively, as of December 31, 2015, which the Partnership expects to recognize over a weighted-average period of 2.99 years and 1.86 years for common units and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2015, 2014, and 2013 was $9.4 million, $8.6 million, and $4.3 million, respectively. Cash payments of $0.4 million were made for vested units in 2014. There were no cash payments made for vested units during the years ended December 31, 2015 and 2013. Performance Unit Grant Awards On May 6, 2015, 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 Partnership’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 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 following table summarizes information about performance units for the year ended December 31, 2015. Performance units Units Weighted- Average Grant- Date Fair Value per Unit Unvested at December 31, 2014 — $ — Granted 947,142 19.00 Vested — — Forfeited — — Unvested at December 31, 2015 947,142 $ 19.00 Unrecognized compensation cost associated with performance unit awards was $2.4 million as of December 31, 2015, which the Partnership expects to recognize over a weighted-average period of 0.56 years. No performance units have vested as of December 31, 2015. Incentive Compensation Summary The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013. Year Ended December 31, Incentive compensation expense 2015 2014 2013 (In thousands) Cash—long-term incentive plan $ 15,064 $ 13,927 $ 10,205 Equity-based compensation—restricted common and subordinated units 10,137 7,194 4,754 Equity-based compensation—restricted performance units 4,743 — — Board of Directors incentive plan 3,120 4,146 2,028 Total incentive compensation expense $ 33,064 $ 25,267 $ 16,987

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
Compensation And Retirement Disclosure [Abstract]
Employee Benefit Plans	NOTE 11—EMPLOYEE BENEFIT PLANS The Partnership sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Partnership makes matching contributions of 100% of employee contributions, up to 5% of compensation. These matching contributions are subject to a graded vesting schedule, with 33% vested after one year, 66% vested after two years and 100% vested after three years of employment with the Partnership. Following three years of employment, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.6 million, $0.6 million, and $0.5 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 12—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space and equipment under cancelable and non-cancelable operating leases that end at various dates through 2019. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $1.8 million for the year ended December 31, 2015 and $1.9 million for both of the years ended December 31, 2014 and 2013. Such amounts are included in general and administrative expense on the consolidated statements of operations. Future minimum lease commitments under non-cancelable leases are as follows: Year Ending December 31, (In thousands) 2016 $ 1,416 2017 1,651 2018 1,683 2019 1 2020 — Total $ 4,751 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 December 31, 2015 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations.

Redeemable Preferred Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Redeemable Preferred Units	NOTE 13—REDEEMABLE PREFERRED UNITS The Partnership has outstanding 77,216 and 157,203 Series A preferred units (the “Redeemable Preferred Units”) with a book value of $79.2 million and $161.2 million as of December 31, 2015 and 2014, respectively. The aforementioned amounts include accrued distributions of $1.9 million and $4.0 million as of December 31, 2015 and 2014, respectively. The Redeemable Preferred Units are classified as mezzanine equity on the consolidated balance sheets since redemption can occur outside the control of the Partnership. The Redeemable Preferred Units are entitled to an annual distribution of 10% of the funded capital of the Redeemable Preferred Units, payable on a quarterly basis in arrears. The Redeemable Preferred Units are convertible into common and subordinated units at the option of the preferred unitholders. The Redeemable 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 Redeemable 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 unitholders of the Redeemable Preferred Units can elect to have the Partnership redeem up to 25% per year of their initial balance of Redeemable Preferred Units at face value, plus any accrued and unpaid distributions, on December 31 of each year from 2014 to 2017. The Partnership shall have the right, at its sole option, to redeem an amount of Redeemable Preferred Units equal to the units being redeemed by an owner of Redeemable Preferred Units on each December 31. Any amount of a given year’s 25% of Redeemable Preferred Units not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 of the following year. For the year ended December 31, 2015, 39,240 Redeemable Preferred Units totaling $39.2 million were converted into 2,750,166 Predecessor units, which included units automatically converted on January 1, 2015. For the year ended December 31, 2014, 221 Redeemable Preferred Units totaling $0.2 million were converted into 15,489 Predecessor units. On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding Redeemable Preferred Units at par value plus unpaid accrued yield. The tender offer expired on December 10, 2015. The Partnership purchased and cancelled 40,747 Redeemable Preferred Units for $1,019.45 per unit for a total cost of $41.5 million, excluding fees and expenses related to the tender offer.

Predecessor Exchange and Equity

Predecessor Exchange and Equity Offerings	12 Months Ended
	Dec. 31, 2015
Statement Of Partners Capital [Abstract]
Predecessor Exchange and Equity Offerings	NOTE 14—PREDECESSOR EXCHANGE AND EQUITY OFFERINGS During 2012, the Predecessor presented a proposal to purchase the noncontrolling interests in certain subsidiaries in exchange for cash or common units of the Predecessor (the “Predecessor Exchange Offer”). The Predecessor Exchange Offer resulted in a majority of the noncontrolling investors electing to exchange their interests in the subsidiaries for cash or common units of the Predecessor. The Predecessor Exchange Offer consisted of the issuance of $1,019.3 million of Predecessor units on January 1, 2013. The Predecessor used borrowings under the Senior Line of Credit and proceeds from a concurrent $412.2 million unit offering (“Predecessor Equity Offering”), effective January 1, 2013, to fund the purchase of the noncontrolling interests. Cash from the Predecessor Equity Offering in excess of the amounts needed for the Predecessor Exchange Offer was used to repay a portion of the Senior Line of Credit and provided additional capital for future acquisitions.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Unit	NOTE 15—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 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 2.3 million common units and 3.1 million subordinated units as of December 31, 2015. At December 31, 2015, 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. As of December 31, 2015, there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU as the inclusion of these units would be antidilutive. The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2015 2014 2013 (In thousands, except per unit amounts) Net income (loss) $ (101,305 ) $ 169,187 $ 168,963 Net income attributable to Predecessor (450 ) (169,187 ) (168,963 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 1,260 — — Distributions on redeemable preferred units subsequent to initial public offering (7,522 ) — — Net loss attributable to the general partner and common and subordinated units subsequent to initial public offering $ (108,017 ) $ — $ — Allocation of net loss subsequent to initial public offering attributable to: General partner interest $ — Common units (54,326 ) Subordinated units (53,691 ) $ (108,017 ) Net loss attributable to common and subordinated units per unit: Per common unit (basic and diluted) $ (0.56 ) Weighted average common units outstanding (basic and diluted) 96,182 Per subordinated unit (basic and diluted) $ (0.56 ) Weighted average subordinated units outstanding (basic and diluted) 95,057

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE 16—SUBSEQUENT EVENTS On January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for $10.0 million. On February 9, 2016, the Board approved a distribution for the period October 1, 2015 to December 31, 2015 of $0.2625 per common unit and $0.18375 per subordinated unit. Distributions were paid on February 26, 2016 to unitholders of record at the close of business on February 19, 2016. On February 19, 2016, the Board granted 717,654 restricted common units and 717,654 restricted performance units at a grant-date fair value of $11.25 per unit under the 2015 LTIP. On March 4, 2016, the Board authorized the repurchase of up to $50.0 million in common units over the next six months.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Disclosure (Unaudited)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Supplemental Oil and Natural Gas Disclosure - Unaudited	Geographic Area of Operation All of the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Kentucky, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the United States. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves are presented on a consolidated basis. Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2015 2014 2013 (In thousands) Acquisition Costs of Properties: 1 Proved $ 2,302 $ 13,215 $ 77,580 Unproved 60,994 35,706 264,710 Exploration Costs 2,592 631 174 Development Costs 60,056 50,595 50,440 Total $ 125,944 $ 100,147 $ 392,904 1 See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment. Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below: As of December 31, 2015 2014 (In thousands) Proved properties $ 1,957,648 $ 1,753,167 Unproved properties 524,563 626,376 Total 2,482,211 2,379,543 Accumulated depreciation, depletion, amortization, and impairment (1,543,796 ) (1,191,861 ) Oil and natural gas properties, net $ 938,415 $ 1,187,682 Oil and Natural Gas Reserve Information—Unaudited The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2012 14,811 273,800 60,444 Revisions of previous estimates 1 1,616 (16,760 ) (1,177 ) Purchases of minerals in place 2 883 5,472 1,795 Extensions, discoveries and other additions 3 4,265 22,848 8,073 Production (2,626 ) (45,400 ) (10,193 ) Net proved reserves at December 31, 2013 18,949 239,960 58,942 Revisions of previous estimates 1 (1,904 ) (20,764 ) (5,365 ) Purchases of minerals in place 4 89 7,439 1,329 Extensions, discoveries and other additions 5 2,938 19,894 6,254 Production (3,005 ) (42,273 ) (10,051 ) Net proved reserves at December 31, 2014 17,067 204,256 51,109 Revisions of previous estimates 1 (197 ) (17,043 ) (3,037 ) Purchases of minerals in place 6 8 367 69 Extensions, discoveries and other additions 7 2,529 57,484 12,110 Production (3,565 ) (41,389 ) (10,463 ) Net proved reserves at December 31, 2015 15,842 203,675 49,788 Net Proved Developed Reserves 8 December 31, 2013 17,290 232,777 56,086 December 31, 2014 16,700 202,888 50,514 December 31, 2015 15,497 174,555 44,590 Net Proved Undeveloped Reserves 9 December 31, 2013 1,659 7,183 2,856 December 31, 2014 367 1,368 595 December 31, 2015 345 29,120 5,198 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells. 2 Includes the acquisition of mineral interests primarily in the Haynesville/Bossier plays as part of the Predecessor Exchange Offer and additional mineral acreage located in the Eagle Ford Shale in Texas. Additionally, this line includes adjustments to reserves related to the pro rata distribution of assets to unrelated third-party investors who chose to take their interests in-kind rather than participate in the Predecessor Exchange Offer. 3 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Granite Wash, and Fayetteville plays. 4 Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas. 5 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays. 6 7 8 Proved developed reserves of 84 MBoe, 87 MBoe, and 119 MBoe as of December 31, 2015, 2014, and 2013, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. 9 As of December 31, 2015, 2014, and 2013, no proved undeveloped reserves were attributable to noncontrolling interests. Standardized Measure of Discounted Future Net Cash Flows—Unaudited Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion. Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 1,211,290 $ 2,493,294 $ 2,693,511 Future production costs (205,861 ) (405,833 ) (393,347 ) Future development costs (84,746 ) (64,968 ) (53,160 ) Future net cash flows (undiscounted) 920,683 2,022,493 2,247,004 Annual discount 10% for estimated timing (365,711 ) (879,399 ) (1,061,747 ) Total 1 $ 554,972 $ 1,143,094 $ 1,185,257 1 Includes standardized measure of discounted future net cash flows of approximately $0.7 million for December 31, 2015 and $1.4 million for both December 31, 2014 and 2013, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2015 2014 2013 (In thousands) Standardized measure, beginning of year $ 1,143,094 $ 1,185,257 $ 928,518 Sales, net of production costs (222,206 ) (391,983 ) (373,655 ) Net changes in prices and production costs related to future production (621,065 ) 75,284 208,291 Extensions, discoveries and improved recovery, net of future production and development costs 165,020 209,651 223,482 Previously estimated development costs incurred during the period 7,084 12,162 22,456 Revisions of estimated future development costs 669 7,854 1,620 Revisions of previous quantity estimates, net of related costs (67,911 ) (110,431 ) (22,687 ) Accretion of discount 114,309 118,526 92,852 Purchases of reserves in place, less related costs 584 24,210 62,887 Other 35,394 12,564 41,493 Standardized measure, end of year $ 554,972 $ 1,143,094 $ 1,185,257 The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Selected Quarterly Financial In

Selected Quarterly Financial Information—Unaudited	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information	Selected Quarterly Financial Information—Unaudited Quarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except for per unit data) 2015 Total revenue $ 91,061 $ 64,803 $ 137,020 $ 100,040 Net income (loss) 17,299 (122,766 ) 53,892 (49,730 ) Net income (loss) attributable to the general partner and common and subordinated units subsequent to initial public offering * (107,587 ) 50,916 (51,346 ) Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) * (0.56 ) 0.27 (0.27 ) Per subordinated unit (basic) * (0.56 ) 0.27 (0.27 ) Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) * (0.56 ) 0.27 (0.27 ) Per subordinated unit (diluted) * (0.56 ) 0.27 (0.27 ) Cash distributions declared and paid per limited partner unit Per common unit * * 0.1615 0.2625 Per subordinated unit * * 0.1615 0.2625 Total assets 1,274,291 1,118,569 1,161,446 1,061,436 Long-term debt 389,000 6,000 43,000 66,000 Total mezzanine equity 120,889 120,904 120,936 79,162 2014 Total revenue $ 127,412 $ 118,937 $ 132,795 $ 169,177 Net income (loss) 69,884 62,111 57,905 (20,713 ) Net income (loss) attributable to the general partner and common and subordinated units subsequent to initial public offering * * * * Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) * * * * Per subordinated unit (basic) * * * * Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) * * * * Per subordinated unit (diluted) * * * * Cash distributions declared per limited partner unit Per common unit * * * * Per subordinated unit * * * * Total assets 1,468,856 1,466,769 1,444,467 1,326,782 Long-term debt 462,500 453,000 430,000 394,000 Total mezzanine equity 161,306 161,122 161,165 161,165 * 1

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of estimates The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments, revenue accruals, asset retirement obligation (“ARO”) liabilities, and determination of the fair value of equity-based awards. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in natural gas or oil prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from estimates.
Cash and Cash Equivalents	Cash and cash equivalents
Concentration of Credit Risk	Concentration of credit risk
Accounts Receivable	Accounts receivable
Derivatives and Financial Instruments	Derivatives and financial instruments Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets
Oil and Natural Gas Properties	Oil and natural gas properties The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved leaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs are assessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired. Mineral interests are assessed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessment is performed by comparing carrying values to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties. As exploration and development work progresses and the reserves associated with the Partnership’s properties become proven, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Acquisition costs of proved properties are amortized on the basis of all proved reserves, both developed and undeveloped, and capitalized development costs are amortized on the basis of proved developed reserves. Proved reserves are quantities of oil and natural gas that can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations. DD&A expense related to the Partnership’s producing oil and natural gas properties was $102.7 million, $109.9 million and $100.6 million for the years ended December 31, 2015, 2014, and 2013, respectively. 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. This evaluation is performed on a field-by-field basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a field to the carrying amount to determine recoverability. When the carrying amount of a field 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 proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate. Impairment of proved oil and natural gas properties was $127.8 million, $117.9 million and $57.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. The impairment primarily resulted from declines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties. The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment using management’s assessment of fair value. The factors used to determine fair value are similar to those previously noted for proved properties. Impairment of unproved properties was $121.8 million for the year ended December 31, 2015. There was no impairment of unproved properties for the years ended December 31, 2014 and 2013. Upon the sale of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value is charged to income. On sale or retirement of an individual well, the proceeds are credited to accumulated DD&A.
Other Property and Equipment	Other property and equipment
Repairs and Maintenance	Repairs and maintenance
Accrued Distribution Payable to Predecessor Unitholders	Accrued distribution payable to Predecessor unitholders
Debt Issuance Costs	Debt issuance costs
Asset Retirement Obligations	Asset retirement obligations
Revenue Recognition	Revenue recognition The Partnership recognizes oil and natural gas revenue from its interests in producing wells when the associated production is sold. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Partnership, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2015 and 2014. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Other sources of revenue received by the Partnership includes mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to other exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. The Partnership recognizes such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable, and the Partnership has no further obligation to refund the payment. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and the Partnership has no further obligation to refund the payment.
Income Taxes	Income taxes Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.
Fair Value of Financial Instruments	Fair value of financial instruments
Incentive Compensation	Incentive compensation Liability awards are awards that are expected to be settled in cash on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans. The Partnership may also recognize liability awards as a result of repurchase options given to the recipients participating in certain incentive plans. Compensation expense for unit-based awards subsequent to the Partnership’s initial public offering is measured by the price of the unit at the measurement date, which is generally the date of grant, and is recognized in general and administrative expense over the requisite service period. Prior to the initial public offering, the Predecessor was privately held and determining the fair value required the Predecessor to make complex and subjective judgments. The Board determined the fair value of the equity-based awards’ unit price prior to the Partnership’s initial public offering by considering various objective and subjective factors, along with input from management. To determine the fair value of the Predecessor, the Predecessor considered information provided by third-party consultants and relied on generally accepted valuation techniques, which included, but were not limited to, the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. These methods were dependent upon various assumptions to develop the estimates in the Predecessor’s operating results, commodity prices, and market-based discount rates. The Predecessor also considered publicly available information on comparable public companies and the Predecessor’s historical transactions and performance in making these estimates. The Predecessor’s limited partnership agreement contained an annual repurchase obligation of 1% of the outstanding units. An annual valuation of the Predecessor was required to establish a value basis for the repurchase obligation. The Predecessor utilized the same valuation for repurchases and issuances of equity, if any, and as the basis for calculating the fair value of its equity awards under its long-term incentive plans. Incentive compensation expense is included in general and administrative expense on the consolidated statements of operations. The total compensation expense related to the common and subordinated unit grants is measured as the number of units granted that are expected to vest multiplied by the grant-date fair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the award agreements over the requisite service periods (generally equivalent to the vesting period).
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 In November 2014, the FASB issued an accounting standards update that clarifies how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Partnership adopted this guidance on January 1, 2016, and there was no material impact to the Partnership’s consolidated financial statements and related disclosures. 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 Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s consolidated financial statements and related disclosures. In September 2015, the FASB issued an accounting standards update that requires that adjustments to provisional amounts identified during the measurement period of a business combination be recognized in the reporting period in which those adjustments are determined, including the effect on earnings, if any, calculated as if the accounting had been completed at the acquisition date. This eliminates the previous requirement to retrospectively account for such adjustments. The new standard also requires additional disclosures related to the income statement effects of adjustments to provisional amounts identified during the measurement period. The guidance is effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s consolidated financial statements and related disclosures.
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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation Liability	The following table describes changes to the Partnership’s ARO liability: For the year ended December 31, 2015 2014 (In thousands) Beginning asset retirement obligations $ 9,381 $ 5,961 Liabilities incurred 272 167 Liabilities settled (143 ) (145 ) Accretion expense 1,075 1,060 Revisions in estimated costs — 2,338 Ending asset retirement obligations $ 10,585 $ 9,381

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Fair Values of the Assets Acquired	The following table summarizes the fair values assigned to the assets acquired as of January 1, 2013: (In thousands) Proved oil and natural gas properties $ 51,573 Unproved oil and natural gas properties 169,150 Net working capital 6,396 Total net assets acquired $ 227,119

Derivatives and Financial Ins28

Derivatives and Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
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 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 $ — $ — $ — As of December 31, 2014 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 $ 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 Partnership’s commodity derivative instruments (both assets and liabilities) are as follows: For the year ended December 31, Derivatives not designated as hedging instruments 2015 2014 2013 (In thousands) Beginning fair value of commodity derivative instruments $ 37,471 $ (1,812 ) $ 5,538 Gain on oil derivative instruments 57,681 27,548 (3,469 ) Gain on natural gas derivative instruments 32,607 9,788 (2,391 ) Net cash received on settlements of oil derivative instruments (41,786 ) (46 ) 505 Net cash (received) paid on settlements of natural gas derivative instruments (21,439 ) 1,993 (1,995 ) Net change in fair value of commodity derivative instruments 27,063 39,283 (7,350 ) Ending fair value of commodity derivative instruments $ 64,534 $ 37,471 $ (1,812 )
Oil and Natural Gas
Derivative [Line Items]
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of December 31, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Collar Contracts: Q4 2015 Call Options 10,000 $ 102.00 $ 102.00 $ 102.00 Put Options 10,000 85.00 85.00 85.00 Oil Swap Contracts: Q4 2015 173,000 59.67 48.65 61.71 Q1 2016 502,000 55.88 48.54 61.34 Q2 2016 455,000 57.30 50.14 61.96 Q3 2016 424,000 58.38 51.27 62.53 Q4 2016 398,000 59.43 52.40 63.07 FY 2017 703,000 58.50 52.73 63.65 The Partnership had the following open derivative contracts for natural gas as of December 31, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 6,780,000 $ 3.26 $ 3.16 $ 3.38 Q2 2016 6,240,000 3.07 3.00 3.14 Q3 2016 5,830,000 3.13 3.06 3.17 Q4 2016 5,400,000 3.25 3.10 3.41 FY 2017 9,650,000 3.33 3.14 3.52 The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2015: Volume Weighted Average Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swap Contracts: Q1 2016 28,000 $ 29.56 $ 29.07 $ 29.79 Q2 2016 81,000 32.60 31.25 33.93 Q3 2016 65,000 35.20 34.41 36.09 Q4 2016 50,000 37.00 36.31 37.73 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2015: Volume Weighted Average Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 340,000 $ 1.98 $ 1.96 $ 1.99 Q2 2016 970,000 2.10 2.03 2.19 Q3 2016 780,000 2.26 2.23 2.28 Q4 2016 550,000 2.42 2.29 2.61

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 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 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 December 31, 2015 Financial Assets Commodity derivative instruments $ — $ 64,534 $ — $ — $ 64,534 Financial Liabilities Commodity derivative instruments — — — — — 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 Non-recurring Basis	The following table presents information about the Partnership’s assets measured at fair value on a non-recurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value 1 Impairment (In thousands) Year Ended December 31, 2015 Impaired oil and natural gas properties $ — $ — $ 156,689 $ 406,258 $ 249,569 Year Ended December 31, 2014 Impaired oil and natural gas properties $ — $ — $ 81,864 $ 199,794 $ 117,930 Year Ended December 31, 2013 Impaired oil and natural gas properties $ — $ — $ 56,318 $ 113,427 $ 57,109 1 Amount represents net book value at the date of assessment.

Credit Facilities (Tables)

Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
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 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)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information about Restricted Units	The following table summarizes information about restricted units for the year ended December 31, 2015. Units Weighted-Average Grant-Date Fair Value per Unit Units Predecessor Common Subordinated Predecessor Common Subordinated Unvested at December 31, 2014 668,119 — — $ 20.81 $ — $ — Granted 441,900 1,110,877 — 18.30 18.98 — Vested (329,190 ) (63,156 ) — 20.87 19.00 — Converted 1 (780,829 ) 338,051 442,778 19.36 19.36 19.36 Forfeited — (23,681 ) — — 19.00 — Unvested at December 31, 2015 — 1,362,091 442,778 $ — $ 19.08 $ 19.36 1 Consistent with all outstanding Predecessor units, the Predecessor restricted unit award agreements were converted into common and subordinated units of the Partnership at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units as described in Note 1 – Business and Basis of Presentation.
Summary of Information about Performance Units	The following table summarizes information about performance units for the year ended December 31, 2015. Performance units Units Weighted- Average Grant- Date Fair Value per Unit Unvested at December 31, 2014 — $ — Granted 947,142 19.00 Vested — — Forfeited — — Unvested at December 31, 2015 947,142 $ 19.00
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 years ended December 31, 2015, 2014, and 2013. Year Ended December 31, Incentive compensation expense 2015 2014 2013 (In thousands) Cash—long-term incentive plan $ 15,064 $ 13,927 $ 10,205 Equity-based compensation—restricted common and subordinated units 10,137 7,194 4,754 Equity-based compensation—restricted performance units 4,743 — — Board of Directors incentive plan 3,120 4,146 2,028 Total incentive compensation expense $ 33,064 $ 25,267 $ 16,987

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Schedule of future minimum lease commitments under non-cancelable leases	Future minimum lease commitments under non-cancelable leases are as follows: Year Ending December 31, (In thousands) 2016 $ 1,416 2017 1,651 2018 1,683 2019 1 2020 — Total $ 4,751

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 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 unit: For the Year Ended December 31, 2015 2014 2013 (In thousands, except per unit amounts) Net income (loss) $ (101,305 ) $ 169,187 $ 168,963 Net income attributable to Predecessor (450 ) (169,187 ) (168,963 ) Net loss attributable to noncontrolling interests subsequent to initial public offering 1,260 — — Distributions on redeemable preferred units subsequent to initial public offering (7,522 ) — — Net loss attributable to the general partner and common and subordinated units subsequent to initial public offering $ (108,017 ) $ — $ — Allocation of net loss subsequent to initial public offering attributable to: General partner interest $ — Common units (54,326 ) Subordinated units (53,691 ) $ (108,017 ) Net loss attributable to common and subordinated units per unit: Per common unit (basic and diluted) $ (0.56 ) Weighted average common units outstanding (basic and diluted) 96,182 Per subordinated unit (basic and diluted) $ (0.56 ) Weighted average subordinated units outstanding (basic and diluted) 95,057

Supplemental Oil and Natural 34

Supplemental Oil and Natural Gas Disclosure (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2015 2014 2013 (In thousands) Acquisition Costs of Properties: 1 Proved $ 2,302 $ 13,215 $ 77,580 Unproved 60,994 35,706 264,710 Exploration Costs 2,592 631 174 Development Costs 60,056 50,595 50,440 Total $ 125,944 $ 100,147 $ 392,904 1 See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.
Capitalized Costs Relating to Oil and Gas Producing Activities	Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below: As of December 31, 2015 2014 (In thousands) Proved properties $ 1,957,648 $ 1,753,167 Unproved properties 524,563 626,376 Total 2,482,211 2,379,543 Accumulated depreciation, depletion, amortization, and impairment (1,543,796 ) (1,191,861 ) Oil and natural gas properties, net $ 938,415 $ 1,187,682
Schedule of Oil and Gas In Process Activities	The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2012 14,811 273,800 60,444 Revisions of previous estimates 1 1,616 (16,760 ) (1,177 ) Purchases of minerals in place 2 883 5,472 1,795 Extensions, discoveries and other additions 3 4,265 22,848 8,073 Production (2,626 ) (45,400 ) (10,193 ) Net proved reserves at December 31, 2013 18,949 239,960 58,942 Revisions of previous estimates 1 (1,904 ) (20,764 ) (5,365 ) Purchases of minerals in place 4 89 7,439 1,329 Extensions, discoveries and other additions 5 2,938 19,894 6,254 Production (3,005 ) (42,273 ) (10,051 ) Net proved reserves at December 31, 2014 17,067 204,256 51,109 Revisions of previous estimates 1 (197 ) (17,043 ) (3,037 ) Purchases of minerals in place 6 8 367 69 Extensions, discoveries and other additions 7 2,529 57,484 12,110 Production (3,565 ) (41,389 ) (10,463 ) Net proved reserves at December 31, 2015 15,842 203,675 49,788 Net Proved Developed Reserves 8 December 31, 2013 17,290 232,777 56,086 December 31, 2014 16,700 202,888 50,514 December 31, 2015 15,497 174,555 44,590 Net Proved Undeveloped Reserves 9 December 31, 2013 1,659 7,183 2,856 December 31, 2014 367 1,368 595 December 31, 2015 345 29,120 5,198 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells. 2 Includes the acquisition of mineral interests primarily in the Haynesville/Bossier plays as part of the Predecessor Exchange Offer and additional mineral acreage located in the Eagle Ford Shale in Texas. Additionally, this line includes adjustments to reserves related to the pro rata distribution of assets to unrelated third-party investors who chose to take their interests in-kind rather than participate in the Predecessor Exchange Offer. 3 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Granite Wash, and Fayetteville plays. 4 Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas. 5 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays. 6 7 8 Proved developed reserves of 84 MBoe, 87 MBoe, and 119 MBoe as of December 31, 2015, 2014, and 2013, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. 9 As of December 31, 2015, 2014, and 2013, no proved undeveloped reserves were attributable to noncontrolling interests.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 1,211,290 $ 2,493,294 $ 2,693,511 Future production costs (205,861 ) (405,833 ) (393,347 ) Future development costs (84,746 ) (64,968 ) (53,160 ) Future net cash flows (undiscounted) 920,683 2,022,493 2,247,004 Annual discount 10% for estimated timing (365,711 ) (879,399 ) (1,061,747 ) Total 1 $ 554,972 $ 1,143,094 $ 1,185,257 1 Includes standardized measure of discounted future net cash flows of approximately $0.7 million for December 31, 2015 and $1.4 million for both December 31, 2014 and 2013, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2015 2014 2013 (In thousands) Standardized measure, beginning of year $ 1,143,094 $ 1,185,257 $ 928,518 Sales, net of production costs (222,206 ) (391,983 ) (373,655 ) Net changes in prices and production costs related to future production (621,065 ) 75,284 208,291 Extensions, discoveries and improved recovery, net of future production and development costs 165,020 209,651 223,482 Previously estimated development costs incurred during the period 7,084 12,162 22,456 Revisions of estimated future development costs 669 7,854 1,620 Revisions of previous quantity estimates, net of related costs (67,911 ) (110,431 ) (22,687 ) Accretion of discount 114,309 118,526 92,852 Purchases of reserves in place, less related costs 584 24,210 62,887 Other 35,394 12,564 41,493 Standardized measure, end of year $ 554,972 $ 1,143,094 $ 1,185,257

Selected Quarterly Financial 35

Selected Quarterly Financial Information—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information	Quarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except for per unit data) 2015 Total revenue $ 91,061 $ 64,803 $ 137,020 $ 100,040 Net income (loss) 17,299 (122,766 ) 53,892 (49,730 ) Net income (loss) attributable to the general partner and common and subordinated units subsequent to initial public offering * (107,587 ) 50,916 (51,346 ) Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) * (0.56 ) 0.27 (0.27 ) Per subordinated unit (basic) * (0.56 ) 0.27 (0.27 ) Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) * (0.56 ) 0.27 (0.27 ) Per subordinated unit (diluted) * (0.56 ) 0.27 (0.27 ) Cash distributions declared and paid per limited partner unit Per common unit * * 0.1615 0.2625 Per subordinated unit * * 0.1615 0.2625 Total assets 1,274,291 1,118,569 1,161,446 1,061,436 Long-term debt 389,000 6,000 43,000 66,000 Total mezzanine equity 120,889 120,904 120,936 79,162 2014 Total revenue $ 127,412 $ 118,937 $ 132,795 $ 169,177 Net income (loss) 69,884 62,111 57,905 (20,713 ) Net income (loss) attributable to the general partner and common and subordinated units subsequent to initial public offering * * * * Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) * * * * Per subordinated unit (basic) * * * * Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) * * * * Per subordinated unit (diluted) * * * * Cash distributions declared per limited partner unit Per common unit * * * * Per subordinated unit * * * * Total assets 1,468,856 1,466,769 1,444,467 1,326,782 Long-term debt 462,500 453,000 430,000 394,000 Total mezzanine equity 161,306 161,122 161,165 161,165 * 1

Business and Basis of Present36

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions	May. 06, 2015USD ($)$ / sharesshares	Dec. 31, 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		61
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	12.9465
Units conversion ratio split up as part of merger	0.4329	0.4329
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	12.9465
Units conversion ratio split up as part of merger	0.5671	0.5671
Preferred Units | Predecessor
Limited Partners Capital Account [Line Items]
Units exchanged in merger	117,963
Units conversion ratio as part of merger	1

Summary of Significant Accoun37

Summary of Significant Accounting Polices - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion and amortization	$ 104,298,000	$ 111,962,000	$ 102,442,000
Impairment of oil and natural gas properties	249,569,000	117,930,000	57,109,000
Amortization expense for debt issue costs	$ 900,000	1,000,000	1,000,000
Predecessor
Summary Of Significant Accounting Policies [Line Items]
Annual repurchase obligation of outstanding units	1.00%
Oil and Natural Gas Properties
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion and amortization	$ 102,700,000	109,900,000	100,600,000
Proved Oil and Natural Gas Properties
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	127,800,000	117,900,000	57,100,000
Unproved Oil And Natural Gas Properties
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties	121,800,000	0	0
Other Property and Equipment
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion and amortization	$ 1,600,000	2,100,000	$ 1,800,000
Other Property and Equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, expected useful lives	3 years
Other Property and Equipment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, expected useful lives	7 years
IPO | Prepaid Expenses and Other Current Assets
Summary Of Significant Accounting Policies [Line Items]
Capitalized issuance costs		$ 7,600,000

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations	$ 9,381	$ 5,961
Liabilities incurred	272	167
Liabilities settled	(143)	(145)
Accretion expense	1,075	1,060	$ 588
Revisions in estimated costs		2,338
Ending asset retirement obligations	$ 10,585	$ 9,381	$ 5,961

Acquisitions - Additional Infor

Acquisitions - Additional Information (Details) - USD ($) $ in Millions	Sep. 24, 2015	Sep. 22, 2015	Aug. 21, 2015	Aug. 05, 2015	Jul. 15, 2015	Jun. 30, 2015	Jun. 02, 2015	Jan. 02, 2013	Jun. 30, 2015	Dec. 31, 2014	Dec. 31, 2012
Various States | Predecessor
Business Acquisition [Line Items]
Purchase of mineral and royalty interest										$ 2.3
Permian Basin
Business Acquisition [Line Items]
Purchase of mineral and royalty interest		$ 3.4	$ 5.8	$ 20.3	$ 7.8	$ 14.4
Permian Basin | Predecessor
Business Acquisition [Line Items]
Purchase of mineral and royalty interest										16
Eagle Ford Shale Play
Business Acquisition [Line Items]
Purchase of mineral and royalty interest	$ 9.2								$ 0.5
Eagle Ford Shale Play | Predecessor
Business Acquisition [Line Items]
Purchase of mineral and royalty interest										11.9
Utica Shale And Marcellus Plays
Business Acquisition [Line Items]
Purchase of mineral and royalty interest							$ 1.8
Haynesville Play | Predecessor
Business Acquisition [Line Items]
Purchase of mineral and royalty interest										$ 24.6
Pure Partners, L.P. and Pure Resources, L.P. (“Pure”) | Predecessor
Business Acquisition [Line Items]
Percentage of interest acquired in business combination											86.40%
Purchased of remaining ownership interest								$ 227.1
Pure Partners, L.P. and Pure Resources, L.P. (“Pure”) | Predecessor | Third-party Investors
Business Acquisition [Line Items]
Percentage of interest acquired in business combination											13.60%

Acquisitions - Schedule of Fair

Acquisitions - Schedule of Fair Values of the Assets Acquired (Details) - USD ($) $ in Thousands	Jan. 02, 2013	Dec. 31, 2015	[1]	Dec. 31, 2014	[1]	Dec. 31, 2013	[1]
Business Combinations [Abstract]
Proved oil and natural gas properties	$ 51,573	$ 2,302		$ 13,215		$ 77,580
Unproved oil and natural gas properties	169,150	$ 60,994		$ 35,706		$ 264,710
Net working capital	6,396
Total net assets acquired	$ 227,119
[1]	See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

Derivatives and Financial Ins41

Derivatives and Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	$ 64,534	$ 37,656
Effect of Counterparty Netting, Assets		(185)
Net Carrying Value on Balance Sheet, Assets	64,534	37,471
Gross Fair Value, Liabilities		185
Effect of Counterparty Netting, Liabilities		(185)
Commodity Derivative Assets, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	48,260	37,656
Effect of Counterparty Netting, Assets		(185)
Net Carrying Value on Balance Sheet, Assets	48,260	37,471
Deferred Charges and Other Long-term Assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	16,274
Net Carrying Value on Balance Sheet, Assets	$ 16,274
Commodity Derivative Liabilities, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities		185
Effect of Counterparty Netting, Liabilities		$ (185)

Derivatives and Financial Ins42

Derivatives and Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain (loss) on commodity derivative instruments	$ 90,288	$ 37,336	$ (5,860)
Net cash (received) paid on settlements of derivative instruments	(63,225)	1,947	(1,490)
Not Designated as Hedging Instrument
Derivative [Line Items]
Beginning fair value of commodity derivative instruments	37,471	(1,812)	5,538
Net change in fair value of commodity derivative instruments	27,063	39,283	(7,350)
Ending fair value of commodity derivative instruments	64,534	37,471	(1,812)
Oil | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments	57,681	27,548	(3,469)
Net cash (received) paid on settlements of derivative instruments	(41,786)	(46)	505
Natural Gas | Not Designated as Hedging Instrument
Derivative [Line Items]
Gain (loss) on commodity derivative instruments	32,607	9,788	(2,391)
Net cash (received) paid on settlements of derivative instruments	$ (21,439)	$ 1,993	$ (1,995)

Derivatives and Financial Ins43

Derivatives and Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument	Mar. 18, 2016MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2015MMBTU$ / bbl$ / MMBTUbbl
Oil | Q4 2015 | 2015 Collar Contracts | Call Options
Derivative [Line Items]
Derivative Contract, Volume | bbl		10,000
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		10,000
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		173,000
Derivative Contract, Weighted Average Price		59.67
Derivative Contract, Price Range Low		48.65
Derivative Contract, Price Range High		61.71
Oil | Q1 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		502,000
Derivative Contract, Weighted Average Price		55.88
Derivative Contract, Price Range Low		48.54
Derivative Contract, Price Range High		61.34
Oil | Q1 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | bbl	28,000
Derivative Contract, Weighted Average Price	29.56
Derivative Contract, Price Range Low	29.07
Derivative Contract, Price Range High	29.79
Oil | Q2 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		455,000
Derivative Contract, Weighted Average Price		57.30
Derivative Contract, Price Range Low		50.14
Derivative Contract, Price Range High		61.96
Oil | Q2 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | bbl	81,000
Derivative Contract, Weighted Average Price	32.60
Derivative Contract, Price Range Low	31.25
Derivative Contract, Price Range High	33.93
Oil | Q3 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		424,000
Derivative Contract, Weighted Average Price		58.38
Derivative Contract, Price Range Low		51.27
Derivative Contract, Price Range High		62.53
Oil | Q3 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | bbl	65,000
Derivative Contract, Weighted Average Price	35.20
Derivative Contract, Price Range Low	34.41
Derivative Contract, Price Range High	36.09
Oil | Q4 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		398,000
Derivative Contract, Weighted Average Price		59.43
Derivative Contract, Price Range Low		52.40
Derivative Contract, Price Range High		63.07
Oil | Q4 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | bbl	50,000
Derivative Contract, Weighted Average Price	37
Derivative Contract, Price Range Low	36.31
Derivative Contract, Price Range High	37.73
Oil | 2017 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | bbl		703,000
Derivative Contract, Weighted Average Price		58.50
Derivative Contract, Price Range Low		52.73
Derivative Contract, Price Range High		63.65
Natural Gas | Q1 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		6,780,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.26
Derivative Contract, Price Range Low | $ / MMBTU		3.16
Derivative Contract, Price Range High | $ / MMBTU		3.38
Natural Gas | Q1 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	340,000
Derivative Contract, Weighted Average Price | $ / MMBTU	1.98
Derivative Contract, Price Range Low | $ / MMBTU	1.96
Derivative Contract, Price Range High | $ / MMBTU	1.99
Natural Gas | Q2 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		6,240,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.07
Derivative Contract, Price Range Low | $ / MMBTU		3
Derivative Contract, Price Range High | $ / MMBTU		3.14
Natural Gas | Q2 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	970,000
Derivative Contract, Weighted Average Price | $ / MMBTU	2.10
Derivative Contract, Price Range Low | $ / MMBTU	2.03
Derivative Contract, Price Range High | $ / MMBTU	2.19
Natural Gas | Q3 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		5,830,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.13
Derivative Contract, Price Range Low | $ / MMBTU		3.06
Derivative Contract, Price Range High | $ / MMBTU		3.17
Natural Gas | Q3 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	780,000
Derivative Contract, Weighted Average Price | $ / MMBTU	2.26
Derivative Contract, Price Range Low | $ / MMBTU	2.23
Derivative Contract, Price Range High | $ / MMBTU	2.28
Natural Gas | Q4 2016 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		5,400,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.25
Derivative Contract, Price Range Low | $ / MMBTU		3.10
Derivative Contract, Price Range High | $ / MMBTU		3.41
Natural Gas | Q4 2016 | Swap Contracts | Swap | Subsequent Event
Derivative [Line Items]
Derivative Contract, Volume | MMBTU	550,000
Derivative Contract, Weighted Average Price | $ / MMBTU	2.42
Derivative Contract, Price Range Low | $ / MMBTU	2.29
Derivative Contract, Price Range High | $ / MMBTU	2.61
Natural Gas | 2017 | Swap Contracts | Swap
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		9,650,000
Derivative Contract, Weighted Average Price | $ / MMBTU		3.33
Derivative Contract, Price Range Low | $ / MMBTU		3.14
Derivative Contract, Price Range High | $ / MMBTU		3.52

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	$ 64,534	$ 37,656
Effect of Counterparty Netting, Assets		(185)
Net Carrying Value on Balance Sheet, Assets	64,534	37,471
Gross Fair Value, Liabilities		185
Effect of Counterparty Netting, Liabilities		(185)
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	64,534	37,656
Effect of Counterparty Netting, Assets		(185)
Net Carrying Value on Balance Sheet, Assets	$ 64,534	37,471
Gross Fair Value, Liabilities		185
Effect of Counterparty Netting, Liabilities		$ (185)

Fair Value Measurements - Sch46

Fair Value Measurements - Schedule of Assets Measured at Fair Value on a Non-recurring Basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Impairment	$ 249,569	$ 117,930	$ 57,109
Fair Value Measurements, Non-recurring Basis
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Net Book Value	406,258	199,794	113,427
Impaired oil and natural gas properties, Impairment	249,569	117,930	57,109
Fair Value Measurements, Non-recurring Basis | Level 3
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	$ 156,689	$ 81,864	$ 56,318

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Predecessor - Officer - USD ($) $ in Millions	Apr. 15, 2010	Dec. 31, 2014
Related Party Transaction [Line Items]
Promissory note, executed amount	$ 0.5
Promissory notes receivable		$ 0.1

Significant Customers - Additio

Significant Customers - Additional Information (Details) - Lease Revenue [Member] - Customer Concentration Risk [Member] - Customer	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Number of customers representing on total revenue	0	1	1
Total revenue represented by one company		10.00%	10.90%
Minimum
Concentration Risk [Line Items]
Total revenue represented by one company	10.00%

Credit Facilities - Additional

Credit Facilities - Additional Information (Details) - USD ($)

May. 15, 2013

Mar. 28, 2013

Dec. 27, 2012

Nov. 09, 2005

Dec. 31, 2015

Dec. 31, 2013

Oct. 28, 2015

Sep. 30, 2015

Jun. 30, 2015

Apr. 10, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Oct. 10, 2008

Line Of Credit Facility [Line Items]

Credit facility

$ 66,000,000

$ 43,000,000

$ 6,000,000

$ 389,000,000

$ 394,000,000

$ 430,000,000

$ 453,000,000

$ 462,500,000

Repayments of lines of credit

$ 46,100,000

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

$ 550,000,000

$ 600,000,000

$ 700,000,000

Line of credit facility, 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

1.92%

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 facility

$ 66,000,000

$ 394,000,000

Line of credit, unused portion of current borrowing base

$ 484,000,000

$ 306,000,000

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%

BSNR II-B Revolving Credit Facility | Predecessor

Line Of Credit Facility [Line Items]

Line of credit facility, expiration date

Apr. 30, 2013

Revolving credit facility

$ 50,000,000

Revolving credit facility period

5 years

Repayments of lines of credit

$ 19,100,000

BSNR III -B Revolving Credit Facility | Predecessor

Line Of Credit Facility [Line Items]

Line of credit facility, expiration date

Nov. 30, 2017

Revolving credit facility

$ 100,000,000

Repayments of lines of credit

$ 27,000,000

Credit Facilities - Borrowing B

Credit Facilities - Borrowing Base Utilization (Details)	12 Months Ended
	Dec. 31, 2015
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%

Incentive Compensation - Additi

Incentive Compensation - Additional Information (Details)	May. 06, 2015USD ($)Timeshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (weighted average grant date fair value) | $ / shares		$ 18.79	$ 20.73	$ 20.78
Fair value of units vested | $		$ 9,400,000	$ 8,600,000	$ 4,300,000
Cash payments of vested units | $		$ 0	$ 400,000	$ 0
Unit Grant Awards | Predecessor
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Repurchase option period		30 days
Percentage Of Equity Awards To Be Vested Classified As Liability		50.00%
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units	1,034,013	1,110,877
Granted (weighted average grant date fair value) | $ / shares		$ 18.98
Unrecognized compensation cost | $		$ 19,600,000
Period of weighted average recognition		2 years 11 months 27 days
Number of performance units vested		63,156
Common Units | Non-employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested	63,156
Subordinate Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost | $		$ 4,700,000
Period of weighted average recognition		1 year 10 months 10 days
Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units		947,142
Granted (weighted average grant date fair value) | $ / shares		$ 19
Unrecognized compensation cost | $		$ 2,400,000
Period of weighted average recognition		6 months 22 days
Number of performance units vested		0
2015 LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common and subordinated units registered for issuance	17,420,310
2015 LTIP | Other Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash awards granted | $	$ 2,700,000
2015 LTIP | Unit Grant Awards | Predecessor | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash settlement of restricted unit awards granted		50.00%
2015 LTIP | Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Target number of common units, Minimum | Time	0
Target number of common units, Maximum | Time	2
2015 LTIP | Restricted Performance Units | March 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common and subordinated units registered for issuance	947,142
Percentage of restricted performance units are eligible to become earned	16.66%
2015 LTIP | 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%
2015 LTIP | 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%
2015 LTIP | 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%
Two Thousand Twelve Long Term Incentive Plan | Performance Cash Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
percentage of cash awards		50.00%
Two Thousand Twelve Long Term Incentive Plan | Performance Cash Awards | Other Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Requisite service period of employees		4 years

Incentive Compensation - Summar

Incentive Compensation - Summary of Information about Restricted Units (Details) - shares		May. 06, 2015	Dec. 31, 2015
Predecessor restricted units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested, beginning of period (in shares)			668,119
Granted (in shares)			441,900
Vested (in shares)			(329,190)
Converted (in shares)	[1]		(780,829)
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)		1,034,013	1,110,877
Vested (in shares)			(63,156)
Converted (in shares)	[1]		338,051
Forfeited(in shares)			(23,681)
Unvested, end of period (in shares)			1,362,091
Subordinate Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Converted (in shares)	[1]		442,778
Unvested, end of period (in shares)			442,778
[1]	Consistent with all outstanding Predecessor units, the Predecessor restricted unit award agreements were converted into common and subordinated units of the Partnership at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units as described in Note 1 – Business and Basis of Presentation

Incentive Compensation - Summ53

Incentive Compensation - Summarize Information about Restricted Common and Subordinated Units (Details) - $ / shares		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (weighted average grant date fair value)		$ 18.79	$ 20.73	$ 20.78
Predecessor restricted units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested, beginning of period (weighted average grant date fair value)		20.81
Granted (weighted average grant date fair value)		18.30
Vested (weighted average grant date fair value)		20.87
Converted (weighted average grant date fair value)	[1]	19.36
Unvested, end of period (weighted average grant date fair value)			$ 20.81
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (weighted average grant date fair value)		18.98
Vested (weighted average grant date fair value)		19
Converted (weighted average grant date fair value)	[1]	19.36
Forfeited (weighted average grant date fair value)		19
Unvested, end of period (weighted average grant date fair value)		19.08
Subordinate Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Converted (weighted average grant date fair value)	[1]	19.36
Unvested, end of period (weighted average grant date fair value)		$ 19.36
[1]	Consistent with all outstanding Predecessor units, the Predecessor restricted unit award agreements were converted into common and subordinated units of the Partnership at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units as described in Note 1 – Business and Basis of Presentation

Incentive Compensation - Summ54

Incentive Compensation - Summarize Information about Restricted Common and Subordinated Units (Parenthetical) (Details) - Predecessor	May. 06, 2015	Dec. 31, 2015
Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units conversion ratio as part of merger	12.9465	12.9465
Units conversion ratio split up as part of merger	0.4329	0.4329
Subordinate Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units conversion ratio as part of merger	12.9465	12.9465
Units conversion ratio split up as part of merger	0.5671	0.5671

Incentive Compensation - Summ55

Incentive Compensation - Summarize Information about Performance Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (weighted average grant date fair value)	$ 18.79	$ 20.73	$ 20.78
Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested, beginning of period (in shares)	947,142
Granted (in shares)	947,142
Vested (in shares)	0
Unvested, beginning of period (weighted average grant date fair value)	$ 19
Granted (weighted average grant date fair value)	$ 19

Incentive Compensation - Summ56

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - 2015 LTIP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 15,064	$ 13,927	$ 10,205
Total incentive compensation expense	33,064	25,267	16,987
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	10,137	7,194	4,754
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	4,743
Board of Directors | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 3,120	$ 4,146	$ 2,028

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Details) - 401(k) Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Plan Disclosure [Line Items]
Maximum tax-deferred contributions	100.00%
Partnership's defined contributions	$ 0.6	$ 0.6	$ 0.5
Maximum
Defined Contribution Plan Disclosure [Line Items]
Matching employee contributions	5.00%
After One Year [Member]
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	33.00%
After Two Years [Member]
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	66.00%
After Three Years [Member]
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	100.00%

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
Rent expense	$ 1,800,000	$ 1,900,000	$ 1,900,000
Provision for remediation costs	$ 0

Commitments and Contingencies59

Commitments and Contingencies - Summary of Future Minimum Lease Commitments Under Non-cancelable Leases (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 1,416
2,017	1,651
2,018	1,683
2,019	1
Total	$ 4,751

Redeemable Preferred Units - Ad

Redeemable Preferred Units - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 06, 2015	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Class Of Stock [Line Items]
Partners' equity - redeemable preferred units, 77 and 157 units outstanding at December 31, 2015 and 2014, respectively		$ 79,162	$ 161,165	$ 120,936	$ 120,904	$ 120,889	$ 161,165	$ 161,122	$ 161,306
Preferred Units
Class Of Stock [Line Items]
Partners' equity, preferred units, outstanding		77,216	157,203
Partners' equity - redeemable preferred units, 77 and 157 units outstanding at December 31, 2015 and 2014, respectively		$ 79,200	$ 161,200
Accrued distributions		$ 1,900	$ 4,000
Preferred units distribution rate		10.00%
Adjusted conversion price		$ 14.2683
Preferred units, redemption terms		The unitholders of the Redeemable Preferred Units can elect to have the Partnership redeem up to 25% per year of their initial balance of Redeemable Preferred Units at face value, plus any accrued and unpaid distributions, on December 31 of each year from 2014 to 2017. The Partnership shall have the right, at its sole option, to redeem an amount of Redeemable Preferred Units equal to the units being redeemed by an owner of Redeemable Preferred Units on each December 31. Any amount of a given year’s 25% of Redeemable 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		39,240	221
Conversion of preferred units to common units		$ 39,200	$ 200
Maximum percentage of preferred units repurchase	100.00%
Purchased and cancelled redeemable preferred units	40,747
Cost of purchased and cancelled redeemable preferred units, per unit	$ 1,019.45
Purchased and cancelled redeemable preferred units, total cost	$ 41,500
Tender offer expiration date	Dec. 10, 2015
Predecessor Units
Class Of Stock [Line Items]
Conversion of preferred units		2,750,166	15,489

Predecessor Exchange and Equi61

Predecessor Exchange and Equity Offerings - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
Predecessor Exchange And Equity Offerings [Line Items]
Issuance of predecessor units under predecessor exchange offer	$ 1,019,340
Predecessor
Predecessor Exchange And Equity Offerings [Line Items]
Issuance of predecessor units under predecessor exchange offer	1,019,340
Proceeds from concurrent equity offering	$ 412,200

Earnings Per Unit - Additional

Earnings Per Unit - Additional Information (Details)	12 Months Ended
	Dec. 31, 2015shares
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	2,300,000
Subordinate Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	3,100,000

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								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share Basic [Line Items]
Net income (loss)	$ (49,730)	$ 53,892	$ (122,766)	$ 17,299	$ (20,713)	$ 57,905	$ 62,111	$ 69,884	$ (101,305)	$ 169,187	$ 168,963
Net loss attributable to noncontrolling interests subsequent to initial public offering									1,260
Distributions on redeemable preferred units subsequent to initial public offering									(7,522)
NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	(51,346)	50,916	(107,587)						(108,017)
Allocation of net 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	$ (51,346)	$ 50,916	$ (107,587)						(108,017)
Common Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ (54,326)
Net loss attributable to common and subordinated units per unit:
Per unit (basic)	$ (0.27)	$ 0.27	$ (0.56)						$ (0.56)
Per unit (diluted)	(0.27)	0.27	(0.56)						$ (0.56)
Weighted average units outstanding (basic and diluted)									96,182
Subordinate Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ (53,691)
Net loss attributable to common and subordinated units per unit:
Per unit (basic)	(0.27)	0.27	(0.56)						$ (0.56)
Per unit (diluted)	$ (0.27)	$ 0.27	$ (0.56)						$ (0.56)
Weighted average units outstanding (basic and diluted)									95,057
Predecessor
Earnings Per Share Basic [Line Items]
Net income (loss)									$ (450)	$ (169,187)	$ (168,963)

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Feb. 19, 2016	Feb. 09, 2016	Jan. 08, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 04, 2016
Subsequent Event [Line Items]
Purchase of mineral and royalty interest				$ 62,278,000	$ 45,552,000	$ 121,562,000
Subsequent Event
Subsequent Event [Line Items]
Distribution declaration date		Feb. 9, 2016
Distribution date of record		Feb. 19, 2016
Distribution date		Feb. 26, 2016
Subsequent Event | Restricted Common Units | 2015 LTIP
Subsequent Event [Line Items]
Board granted	717,654
Grant fair value	$ 11.25
Subsequent Event | Restricted Performance Units | 2015 LTIP
Subsequent Event [Line Items]
Board granted	717,654
Grant fair value	$ 11.25
Subsequent Event | Common Units
Subsequent Event [Line Items]
Quarterly cash distribution declared		$ 0.2625
Subsequent Event | Common Units | Maximum
Subsequent Event [Line Items]
Authorized unit repurchased							$ 50,000,000
Subsequent Event | Subordinate Units
Subsequent Event [Line Items]
Quarterly cash distribution declared		$ 0.18375
Subsequent Event | Permian Basin
Subsequent Event [Line Items]
Purchase of mineral and royalty interest			$ 10,000,000

Supplemental Oil and Natural 65

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities (Details) - USD ($) $ in Thousands		Jan. 02, 2013	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Acquisition Costs of Properties:
Proved		$ 51,573	$ 2,302	[1]	$ 13,215	[1]	$ 77,580	[1]
Unproved		$ 169,150	60,994	[1]	35,706	[1]	264,710	[1]
Exploration Costs	[1]		2,592		631		174
Development Costs	[1]		60,056		50,595		50,440
Total	[1]		$ 125,944		$ 100,147		$ 392,904
[1]	See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

Supplemental Oil and Natural 66

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Oil and Natural Gas Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Proved properties	$ 1,957,648	$ 1,753,167
Unproved properties	524,563	626,376
Total	2,482,211	2,379,543
Accumulated depreciation, depletion, amortization, and impairment	(1,543,796)	(1,191,861)
Oil and natural gas properties, net	$ 938,415	$ 1,187,682

Supplemental Oil and Natural 67

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Estimated Net Quantities of Partnership Proved, Proved Developed and Proved Undeveloped Oil and Natural Gas Reserve (Details)		12 Months Ended
		Dec. 31, 2015MBoeMBblsMMcf		Dec. 31, 2014MBoeMBblsMMcf		Dec. 31, 2013MBoeMBblsMMcf
Reserve Quantities [Line Items]
Balance at the beginning of the period | MBoe		51,109		58,942		60,444
Revisions of previous estimates | MBoe		(3,037)		(5,365)		(1,177)
Purchases of minerals in place | MBoe		69		1,329		1,795
Extensions, discoveries and other additions | MBoe		12,110		6,254		8,073
Production | MBoe		(10,463)		(10,051)		(10,193)
Balance at the end of the period | MBoe		49,788		51,109		58,942
Net Proved Developed Reserves | MBoe		44,590		50,514		56,086
Net Proved Undeveloped Reserves | MBoe		5,198		595		2,856
Crude Oil
Reserve Quantities [Line Items]
Balance at the beginning of the period | MBbls		17,067		18,949		14,811
Revisions of previous estimates | MBbls	[1]	(197)		(1,904)		1,616
Purchases of minerals in place | MBbls		8	[2]	89	[3]	883	[4]
Extensions, discoveries and other additions | MBbls		2,529	[5]	2,938	[6]	4,265	[7]
Production | MBbls		(3,565)		(3,005)		(2,626)
Balance at the End of the period | MBbls		15,842		17,067		18,949
Net proved developed reserves | MBbls	[8]	15,497		16,700		17,290
Net proved undeveloped reserves | MBbls	[9]	345		367		1,659
Natural Gas
Reserve Quantities [Line Items]
Balance at the beginning of the period | MMcf		204,256		239,960		273,800
Revisions of previous estimates | MMcf	[1]	(17,043)		(20,764)		(16,760)
Purchases of minerals in place | MMcf		367	[2]	7,439	[3]	5,472	[4]
Extensions, discoveries and other additions | MMcf		57,484	[5]	19,894	[6]	22,848	[7]
Production | MMcf		(41,389)		(42,273)		(45,400)
Balance at the End of the period | MMcf		203,675		204,256		239,960
Net proved developed reserves | MMcf	[8]	174,555		202,888		232,777
Net proved undeveloped reserves | MMcf	[9]	29,120		1,368		7,183
[1]	Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells.
[2]	Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.
[3]	Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.
[4]	Includes the acquisition of mineral interests primarily in the Haynesville/Bossier plays as part of the Predecessor Exchange Offer and additional mineral acreage located in the Eagle Ford Shale in Texas. Additionally, this line includes adjustments to reserves related to the pro rata distribution of assets to unrelated third-party investors who chose to take their interests in-kind rather than participate in the Predecessor Exchange Offer.
[5]	Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays.
[6]	Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.
[7]	Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Granite Wash, and Fayetteville plays.
[8]	Proved developed reserves of 84 MBoe, 87 MBoe, and 119 MBoe as of December 31, 2015, 2014, and 2013, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
[9]	As of December 31, 2015, 2014, and 2013, no proved undeveloped reserves were attributable to noncontrolling interests

Supplemental Oil and Natural 68

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Estimated Net Quantities of Partnership Proved, Proved Developed and Proved Undeveloped Oil and Natural Gas Reserve (Parenthetical) (Details) - MBoe	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reserve Quantities [Line Items]
Net Proved Developed Reserves	44,590	50,514	56,086
Net Proved Undeveloped Reserves	5,198	595	2,856
Noncontrolling Interest
Reserve Quantities [Line Items]
Net Proved Developed Reserves	84	87	119
Net Proved Undeveloped Reserves	0	0	0

Supplemental Oil and Natural 69

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Future cash inflows	$ 1,211,290	$ 2,493,294	$ 2,693,511
Future production costs	(205,861)	(405,833)	(393,347)
Future development costs	(84,746)	(64,968)	(53,160)
Future net cash flows (undiscounted)	920,683	2,022,493	2,247,004
Annual discount 10% for estimated timing	(365,711)	(879,399)	(1,061,747)
Standardized measure of discounted future net cash flows	$ 554,972	$ 1,143,094	$ 1,185,257	$ 928,518

Supplemental Oil and Natural 70

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 554,972	$ 1,143,094	$ 1,185,257	$ 928,518
Noncontrolling Interest
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 700	$ 1,400	$ 1,400

Supplemental Oil and Natural 71

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Standardized measure, beginning of year	$ 1,143,094	$ 1,185,257	$ 928,518
Sales, net of production costs	(222,206)	(391,983)	(373,655)
Net changes in prices and production costs related to future production	(621,065)	75,284	208,291
Extensions, discoveries and improved recovery, net of future production and development costs	165,020	209,651	223,482
Previously estimated development costs incurred during the period	7,084	12,162	22,456
Revisions of estimated future development costs	669	7,854	1,620
Revisions of previous quantity estimates, net of related costs	(67,911)	(110,431)	(22,687)
Accretion of discount	114,309	118,526	92,852
Purchases of reserves in place, less related costs	584	24,210	62,887
Other	35,394	12,564	41,493
Standardized measure, end of year	$ 554,972	$ 1,143,094	$ 1,185,257

Selected Quarterly Financial 72

Selected Quarterly Financial Information - Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interim Reporting [Line Items]
Total revenue	$ 100,040	$ 137,020	$ 64,803	$ 91,061	$ 169,177	$ 132,795	$ 118,937	$ 127,412	$ 392,924	$ 548,321	$ 463,559
Net income (loss)	(49,730)	53,892	(122,766)	17,299	(20,713)	57,905	62,111	69,884	(101,305)	169,187	$ 168,963
Net income (loss) attributable to the general partner and common and subordinated units subsequent to initial public offering	(51,346)	50,916	(107,587)						(108,017)
Cash distributions declared and paid per limited partner unit
Total assets	1,061,436	1,161,446	1,118,569	1,274,291	1,326,782	1,444,467	1,466,769	1,468,856	1,061,436	1,326,782
Long-term debt	66,000	43,000	6,000	389,000	394,000	430,000	453,000	462,500	66,000	394,000
Total mezzanine equity	$ 79,162	$ 120,936	$ 120,904	$ 120,889	$ 161,165	$ 161,165	$ 161,122	$ 161,306	$ 79,162	$ 161,165
Common Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic)	$ (0.27)	$ 0.27	$ (0.56)						$ (0.56)
Per unit (diluted)	(0.27)	0.27	(0.56)						(0.56)
Cash distributions declared and paid per limited partner unit
Per unit	0.2625	0.1615							0.4240
Subordinate Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic)	(0.27)	0.27	(0.56)						(0.56)
Per unit (diluted)	(0.27)	0.27	$ (0.56)						(0.56)
Cash distributions declared and paid per limited partner unit
Per unit	$ 0.2625	$ 0.1615							$ 0.4240