Black Stone Minerals (BSM) 10-K 28 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 20, 2018	Jun. 30, 2017
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,197,800,850
Common Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		104,258,290
Subordinated Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		95,388,424
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		24,803
Cumulative Convertible Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 5,642	$ 9,772
Accounts receivable	80,695	68,181
Commodity derivative assets	94	0
Prepaid expenses and other current assets	1,212	1,036
TOTAL CURRENT ASSETS	87,643	78,989
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $988,720 and $605,736 at December 31, 2017 and 2016, respectively	3,247,613	2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,766,842)	(1,652,930)
Oil and natural gas properties, net	1,480,771	1,044,143
Other property and equipment, net of accumulated depreciation of $14,433 and $14,327 at December 31, 2017 and 2016, respectively	559	528
NET PROPERTY AND EQUIPMENT	1,481,330	1,044,671
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,478	5,167
TOTAL ASSETS	1,576,451	1,128,827
CURRENT LIABILITIES
Accounts payable	2,464	4,142
Accrued liabilities	52,631	50,952
Commodity derivative liabilities	4,222	16,237
Other current liabilities	417	0
TOTAL CURRENT LIABILITIES	59,734	71,331
LONG-TERM LIABILITIES
Credit facility	388,000	316,000
Accrued incentive compensation	3,648	1,485
Commodity derivative liabilities	1,263	482
Deferred revenue	0	518
Asset retirement obligations	14,092	13,350
Other long-term liabilities	19,171	0
TOTAL LIABILITIES	485,908	403,166
COMMITMENTS AND CONTINGENCIES (Note 11)
MEZZANINE EQUITY
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively	322,422	54,015
EQUITY
Partners' equity — general partner interest	0	0
Noncontrolling interests	867	1,021
TOTAL EQUITY	768,121	671,646
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,576,451	1,128,827
Series A Redeemable Preferred Units [Member]
MEZZANINE EQUITY
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively	27,028	54,015
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively	295,394	0
Common Units
EQUITY
Partners' equity - units	603,116	489,023
Subordinated Units
EQUITY
Partners' equity - units	$ 164,138	$ 181,602

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties, unproved property costs	$ 988,720	$ 605,736
Other property and equipment accumulated depreciation and amortization	$ 14,433	$ 14,327
Preferred Units
Partners' equity, preferred units, outstanding (in units)	26,363	52,691
Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in units)	14,711,000	0
Common Units
Partners' equity - units, outstanding	103,456,000	95,721,000
Subordinated Units
Partners' equity - units, outstanding	95,388,000	95,164,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUE
Oil and condensate sales	$ 169,728	$ 142,382	$ 163,538
Natural gas and natural gas liquids sales	190,967	122,836	116,018
Gain (loss) on commodity derivative instruments	26,902	(36,464)	90,288
Lease bonus and other income	42,062	32,079	23,080
TOTAL REVENUE	429,659	260,833	392,924
OPERATING (INCOME) EXPENSE
Lease operating expense	17,280	18,755	21,583
Production costs and ad valorem taxes	47,474	35,464	35,767
Exploration expense	618	645	2,592
Depreciation, depletion and amortization	114,534	102,487	104,298
Impairment of oil and natural gas properties	0	6,775	249,569
General and administrative	77,574	73,139	77,175
Accretion of asset retirement obligations	1,026	892	1,075
(Gain) loss on sale of assets, net	(931)	(4,793)	(4,873)
Other expense	0	0	1,593
TOTAL OPERATING EXPENSE	257,575	233,364	488,779
INCOME (LOSS) FROM OPERATIONS	172,084	27,469	(95,855)
OTHER INCOME (EXPENSE)
Interest and investment income	49	656	58
Interest expense	(15,694)	(7,547)	(6,418)
Other income (expense)	714	(390)	910
TOTAL OTHER EXPENSE	(14,931)	(7,281)	(5,450)
NET INCOME (LOSS)	157,153	20,188	(101,305)
Net income attributable to noncontrolling interests subsequent to initial public offering	34	12	1,260
Distributions on Series A redeemable preferred units subsequent to initial public offering	(3,117)	(5,763)	(7,522)
Distributions on Series B cumulative convertible preferred units	(1,925)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	152,145	14,437	(108,017)
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
General partner interest	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	152,145	14,437	(108,017)
Predecessor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	0	0	(450)
Common Units
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of loss	$ 98,389	$ 24,669	$ (54,326)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in usd per share)	$ 1.01	$ 0.26	$ (0.56)
Weighted average units outstanding, basic (in shares)	97,400	96,073	96,182
Per unit (diluted) (in usd per share)	$ 1.01	$ 0.26	$ (0.56)
Weighted average units outstanding, diluted (in shares)	97,400	96,243	96,182
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit (in usd per share)	$ 1.20	$ 1.10	$ 0.42
Subordinated Units
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
Allocation of loss	$ 53,756	$ (10,232)	$ (53,691)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in usd per share)	$ 0.56	$ (0.11)	$ (0.56)
Weighted average units outstanding, basic (in shares)	95,149	95,138	95,057
Per unit (diluted) (in usd per share)	$ 0.56	$ (0.11)	$ (0.56)
Weighted average units outstanding, diluted (in shares)	95,149	95,138	95,057
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit (in usd per share)	$ 0.79	$ 0.74	$ 0.42

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Series A Redeemable Preferred Units	Series B Cumulative Convertible Preferred Units	Common Units	Partners' Equity [Member]	Subordinated Units	Partners Equity Common Units	Partners Equity Common UnitsSeries A Redeemable Preferred Units	Partners Equity Common UnitsSeries B Cumulative Convertible Preferred Units	Partners Equity Subordinated Units	Partners Equity Subordinated UnitsSeries A Redeemable Preferred Units	Partners Equity Subordinated UnitsSeries B Cumulative Convertible Preferred Units	Noncontrolling Interest
Balance at the beginning of the period, units (Predecessor) at Dec. 31, 2014				164,484
Balance at the beginning of the period (Predecessor) at Dec. 31, 2014					$ 653,217
Balance at the beginning of the period at Dec. 31, 2014	$ 653,217
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units | Predecessor				2,750
Conversion of redeemable preferred units | Predecessor					39,240
Conversion of redeemable preferred units	39,240
Issuance of units for acquisitions, units | Predecessor				562
Repurchases of units, units | Predecessor				(164)
Repurchases of units | Predecessor					(3,015)
Repurchases of units	(3,015)
Distributions to Predecessor unitholders and noncontrolling interests | Predecessor					(73,205)
Distributions to Predecessor unitholders and noncontrolling interests	(73,205)
Distributions on Predecessor redeemable preferred units | Predecessor					(4,040)
Distributions on Predecessor redeemable preferred units	(4,040)
Net income (loss) | Predecessor	450				450
Net income (loss)	(101,755)						$ (50,543)			$ (49,952)			$ (1,260)
Allocation of predecessor units and equity, units | Predecessor				(167,632)
Allocation of predecessor units and equity, units				72,575		95,057
Allocation of Predecessor units and equity | Predecessor					(612,647)
Allocation of Predecessor units and equity							264,235			345,875			2,537
Issuance of common units for initial public offering, net of offering costs, units				22,500
Issuance of common units for initial public offering, net of offering costs	391,500						391,500
Restricted units granted, net of forfeitures, units				1,087
Equity-based compensation	18,000						14,181			3,819
Distributions	(81,220)						(40,783)			(40,304)			(133)
Charges to partners' equity for accrued distribution equivalent rights	(159)						(159)
Distributions on Series A redeemable preferred units		$ (7,522)						$ (3,783)			$ (3,739)
Balance at the end of the period, units (Predecessor) at Dec. 31, 2015				0
Balance at the end of the period, units at Dec. 31, 2015				96,162		95,057
Balance at the end of the period (Predecessor) at Dec. 31, 2015					0
Balance at the end of the period at Dec. 31, 2015	831,491						574,648			255,699			1,144
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units				184		241
Conversion of redeemable preferred units	6,064						2,625			3,439
Repurchases of units, units				(1,618)		(78)
Repurchases of units	(27,436)						(27,436)
Net income (loss)	20,188						27,565			(7,365)			(12)
Restricted units granted, net of forfeitures, units				993		(56)
Equity-based compensation	23,845						21,022			2,823
Distributions	(176,055)						(105,817)			(70,127)			(111)
Charges to partners' equity for accrued distribution equivalent rights	(688)						(688)
Distributions on Series A redeemable preferred units		$ (5,763)						$ (2,896)			$ (2,867)
Balance at the end of the period, units (Predecessor) at Dec. 31, 2016				0
Balance at the end of the period, units at Dec. 31, 2016				95,721		95,164
Balance at the end of the period (Predecessor) at Dec. 31, 2016					0
Balance at the end of the period at Dec. 31, 2016	671,646						489,023			181,602			1,021
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units				201		263
Conversion of redeemable preferred units	6,624						2,868			3,756
Issuance of units for acquisitions, units				4,348
Issuance of units for property acquisitions	71,723						71,723
Repurchases of units, units				(446)		(39)
Repurchases of units	(8,185)						(7,893)			(292)
Net income (loss)	157,153						101,891			55,296			(34)
Issuance of common units for initial public offering, net of offering costs, units				2,002
Issuance of common units for initial public offering, net of offering costs	32,458						32,458
Restricted units granted, net of forfeitures, units				1,630
Equity-based compensation	39,357						39,205			152
Distributions	(194,919)						(119,963)			(74,836)			(120)
Charges to partners' equity for accrued distribution equivalent rights	(2,694)						(2,694)
Distributions on Series A redeemable preferred units	(3,117)		$ (1,925)				(1,577)		$ (1,925)	(1,540)		$ 0
Balance at the end of the period, units (Predecessor) at Dec. 31, 2017				0
Balance at the end of the period, units at Dec. 31, 2017				103,456		95,388
Balance at the end of the period (Predecessor) at Dec. 31, 2017					$ 0
Balance at the end of the period at Dec. 31, 2017	$ 768,121						$ 603,116			$ 164,138			$ 867

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 157,153	$ 20,188	$ (101,305)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	114,534	102,487	104,298
Impairment of oil and natural gas properties	0	6,775	249,569
Accretion of asset retirement obligations	1,026	892	1,075
Amortization of deferred charges	877	871	935
(Gain) loss on commodity derivative instruments	(26,902)	36,464	(90,288)
Net cash received (paid) on settlement of commodity derivative instruments	15,211	44,789	63,225
Equity-based compensation	33,044	43,138	18,000
(Gain) loss on sale of assets, net	(931)	(4,793)	(4,873)
Changes in operating assets and liabilities:
Accounts receivable	(6,084)	(29,759)	33,586
Prepaid expenses and other current assets	(177)	(180)	95
Accounts payable and accrued liabilities	(3,585)	(23,029)	11,221
Deferred revenue	(2,086)	(870)	(660)
Settlement of asset retirement obligations	(228)	(317)	(143)
NET CASH PROVIDED BY OPERATING ACTIVITIES	281,852	196,656	284,735
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(425,667)	(141,136)	(62,278)
Additions to oil and natural gas properties	(58,648)	(80,179)	(54,244)
Purchases of other property and equipment	(207)	(425)	(181)
Proceeds from the sale of oil and natural gas properties	11,102	198	25,705
Proceeds from farmouts of oil and natural gas properties	19,171	0	0
NET CASH USED IN INVESTING ACTIVITIES	(454,249)	(221,542)	(90,998)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs	32,458	0	399,087
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs	293,469	0	0
Distributions to noncontrolling interests	(120)	(111)	(208)
Redemption of Series A redeemable preferred units	(19,704)	(18,461)	(40,747)
Borrowings under credit facility	292,500	349,000	245,600
Repayments under credit facility	(220,500)	(99,000)	(573,600)
Debt issuance costs	(3,075)	(239)	(1,376)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	168,267	21,425	(195,307)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(4,130)	(3,461)	(1,570)
Cash and cash equivalents — beginning of the year	9,772	13,233	14,803
Cash and cash equivalents — end of the year	5,642	9,772	13,233
SUPPLEMENTAL DISCLOSURE
Interest paid	14,761	6,535	5,478
NON-CASH ACTIVITIES
Conversion of Series A redeemable preferred units	6,624	6,064	39,240
Accrued distributions payable to Series A redeemable preferred unitholders	(660)	(1,324)	(2,016)
Accrued distributions payable to Series B cumulative convertible preferred unitholders	(1,925)	0	0
Additions to oil and natural gas properties financed through accounts payable and accrued liabilities	34,247	26,553	21,496
Public offering costs capitalized and offset against proceeds from initial public offering	0	0	7,587
Asset retirement obligations incurred and revisions in estimated costs	391	2,009	272
Accrued distribution equivalent rights	2,694	847	159
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	0	0	(450)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	0	0	(126,383)
Repurchases of common and subordinated units	0	0	(3,015)
NON-CASH ACTIVITIES
Accrued distributions payable to Predecessor unitholders	0	0	(53,248)
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(194,799)	(175,943)	(81,087)
Repurchases of common and subordinated units	(8,185)	(27,436)	0
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (3,777)	$ (6,385)	$ (13,578)

Business and Basis of Presentat

Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business and Basis of Presentation	BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $ 391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its Credit Facility, as defined in Note 8 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.” 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 and royalty interests in the United States ("U.S.") . 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 Series A redeemable preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries. In addition to mineral interests, which make up the vast majority of the asset base, the Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. Basis of Presentation The accompanying audited consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). The consolidated financial statements include the consolidated results of the Partnership, which also includes the results of the Noble Acquisition (as defined below) for the period from November 28, 2017 through December 31, 2017, as discussed in Note 4 – Oil and Natural Gas Properties Acquisitions. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those 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, and 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 estimates 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 commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the 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 oil or natural gas 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 predicted accurately, actual results could differ significantly from estimates. Cash and Cash Equivalents The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Accounts Receivable The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry. Commodity Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. 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 sheets. 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 derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. Concentration of Credit Risk Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. The Partnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 7 – Significant Customers for further discussion. Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 5 – Commodity Derivative Financial Instruments for further discussion. Oil and Natural Gas Properties The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. 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 cost. The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit. As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, 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. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. 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 $ 114.3 million , $ 102.4 million and $ 102.7 million for the years ended December 31, 2017 , 2016 , and 2015 , 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 depletable unit basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit 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. There was no impairment of proved oil and natural gas properties for the year ended December 31, 2017. Impairment of proved oil and natural gas properties was $ 4.9 million and $ 127.8 million for the years ended December 31, 2016 and 2015 , respectively. The impairments 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. Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the year ended December 31, 2017. Impairment of unproved properties was $ 1.9 million and $ 121.8 million for the years ended December 31, 2016 and 2015, respectively, as 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. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded. Other Property and Equipment Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Depreciation and amortization expense totaled $ 0.2 million , $ 0.1 million , and $ 1.6 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Repairs and Maintenance The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable. Accrued Liabilities Accrued liabilities consisted of the following as of December 31, 2017 and 2016: As of December 31, 2017 2016 Accrued liabilities: (in thousands) Accrued capital expenditures $ 28,711 $ 17,775 Accrued incentive compensation 16,503 20,898 Accrued property taxes 4,090 3,175 Accrued other 3,327 9,104 Total accrued liabilities $ 52,631 $ 50,952 Debt Issuance Costs Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issuance costs was $ 0.9 million , $ 0.9 million , and $ 0.9 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, and is included in interest expense in the consolidated statements of operations. Asset Retirement Obligations Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset. Revenue Recognition The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. 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, 2017 and 2016 . 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 include mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to 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 The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxes are not material. 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. 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 The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31, 2017 and 2016 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurements for further discussion. Incentive Compensation Incentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant date fair values. Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units 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. Incentive compensation expense is charged to general and administrative expense on the consolidated statements of operations. See Note 9 – Incentive Compensation for additional discussion. Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersede ASC 605, Revenue Recognition . Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures. The Partnership has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership intends to use the modified retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018, and does not anticipate recording or disclosing any material transition adjustments upon adoption. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership intends to use the retrospective transition method upon adoption of the new guidance on the effective date of January 1, 2018 and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership will adopt the new guidance prospectively as of the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met: • The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified. • The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified. • The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Partnership will adopt the new guidance prospectively to all awards modified on or after the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	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 working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability for the periods presented: For the year ended December 31, 2017 2016 (in thousands) Beginning asset retirement obligations $ 13,350 $ 10,585 Liabilities incurred 308 2,009 Liabilities settled (228 ) (317 ) Accretion expense 1,026 892 Revisions in estimated costs 83 181 Dispositions (30 ) — Ending asset retirement obligations $ 14,509 $ 13,350 Current asset retirement obligations $ 417 $ — Non-current asset retirement obligations $ 14,092 $ 13,350

Oil and Natural Gas Properties

Oil and Natural Gas Properties Acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Oil and Natural Gas Properties Acquisitions	Noble Acquisition On November 28, 2017, BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition." The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross ( 140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota. The Partnership funded the $335 million purchase price (before customary post-closing adjustments) using (i) approximately $300 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group ("the Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35 million from borrowings under its Credit Facility. See additional discussion of the Series B cumulative convertible preferred units in Note 12 – Preferred Units. The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date. The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Cash Consideration Paid Acquisition-Related Costs 1 Proved Unproved Net Working Capital Total Fair Value (in thousands) Noble Assets $ 68,877 $ 259,749 $ 5,917 $ 334,543 $ 334,543 $ 247 1 Acquisition-related costs were expensed and included in the general and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017. The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change. Actual and Pro Forma Impact of Noble Acquisition (Unaudited) Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the year ended December 31, 2017 was $2.8 million . The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016. For the Year Ended December 31, 2017 2016 (in thousands, except per unit amounts) Revenue and other income $ 468,103 $ 288,772 Net income (loss) $ 178,970 $ 33,264 Net income (loss) attributable to noncontrolling interests 34 12 Distributions on Series A redeemable preferred units (3,117 ) (5,763 ) Distributions on Series B cumulative convertible preferred units (21,000 ) (21,000 ) Net income (loss) attributable to the general partner and common and subordinated units $ 154,887 $ 6,513 Allocation of net income (loss): General partner interest — — Common units 99,776 20,696 Subordinated units 55,111 (14,183 ) $ 154,887 $ 6,513 Net income (loss) attributable to limited partners per common and subordinated unit: Per common unit (basic) $ 1.02 $ 0.22 Per subordinated unit (basic) $ 0.58 $ (0.15 ) Per common unit (diluted) $ 1.02 $ 0.22 Per subordinated unit (diluted) $ 0.58 $ (0.15 ) The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2016. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments: • Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets. • Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility. • Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units. • The Series B cumulative convertible preferred units were excluded from the calculation of pro forma diluted earnings per common unit for the periods presented above due to their antidilutive effect under the if-converted method; the Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit. 2017 Acquisitions In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests, which also included producing properties, during the year ended December 31, 2017, as reflected in the table below. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility. Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued Acquisition-Related Costs 1 (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 27,380 $ 12,026 $ 1,162 June 5,006 45,477 — 50,483 4,802 45,681 1,481 August 3,277 9,984 — 13,261 4,289 8,972 107 September 3,120 — — 3,120 3,120 — — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 39,591 $ 66,679 $ 2,750 1 Acquisition-related costs were expensed and included in the general and administrative expense line item of the 2017 consolidated statement of operations. In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as reflected in the table below. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility. Assets Acquired Consideration Paid Unproved Cash Fair Value of Common Units Issued (in thousands) Q1 2017 $ 21,189 $ 21,017 $ 172 Q2 2017 13,329 13,329 — Q3 2017 19,946 15,205 4,741 Q4 2017 2,267 2,137 130 Total acquired $ 56,731 $ 51,688 $ 5,043 Farmout Agreements On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership's working interests in such wells ( 40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of the Partnership’s working interest ( 20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. For the year ended December 31, 2017 , the Partnership received $13.6 million from Canaan under the agreement. All amounts received in 2017 are included in the Other long-term liabilities line of our December 31, 2017 consolidated balance sheet, as none of the drilled wells had been completed nor had any working interest been assigned to Canaan as of the balance sheet date. On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining approximate 20% working interest ( 10% working interest on an 8/8th basis) not covered by the Canaan Farmout, as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by its other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding the Partnership's working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells. For the year ended December 31, 2017 , the Partnership received $5.6 million from Pivotal under the agreement. All amounts received in 2017 are included in the Other long-term liabilities line of our December 31, 2017 consolidated balance sheet, as none of the drilled wells had been completed nor had any working interest been assigned to Pivotal as of the balance sheet date. 2016 Acquisitions During the year ended December 31, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage in a diverse oil and natural gas mineral asset package, and also completed an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair value assigned to the properties acquired: Assets Acquired Cash Consideration Paid Proved Unproved Net Working Capital ARO Total Fair Value (in thousands) June 2016 $ 39,735 $ 79,827 $ 2,064 $ (50 ) $ 121,576 $ 121,576 The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash, respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.2 million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's Credit Facility. 2015 Acquisitions During the year ended December 31, 2015, the Partnership acquired mineral and royalty interests in the Permian Basin for $51.7 million , mineral and royalty interests and non-operated working interests in the Eagle Ford Shale resource play for $9.7 million , and overriding royalty interests in the Utica Shale and Marcellus Shale resource plays for $1.8 million . All 2015 acquisition transactions were funded via borrowings under the Partnership's Credit Facility.

Commodity Derivative Financial

Commodity Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Financial Instruments	COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes. As of December 31, 2017 , the Partnership's open derivatives contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership's derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. 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, 2017 and 2016 . See Note 6 – Fair Value Measurements for further discussion. The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2017 , the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of the Partnership's counterparties are lenders under the Partnership's Credit Facility. The Partnership would have been at risk of losing a fair value amount of $12.1 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of December 31, 2017 . The tables below summarize the fair value and classification of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at December 31, 2017 and 2016: As of December 31, 2017 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 $ 10,713 $ (10,619 ) $ 94 Long-term asset Deferred charges and other long-term assets 1,392 (1,029 ) 363 Total assets $ 12,105 $ (11,648 ) $ 457 Liabilities: Current liability Commodity derivative liabilities $ 14,841 $ (10,619 ) $ 4,222 Long-term liability Commodity derivative liabilities 2,292 (1,029 ) 1,263 Total liabilities $ 17,133 $ (11,648 ) $ 5,485 As of December 31, 2016 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 3,879 $ (3,879 ) $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ 3,879 $ (3,879 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 20,116 $ (3,879 ) $ 16,237 Long-term liability Commodity derivative liabilities 482 — 482 Total liabilities $ 20,598 $ (3,879 ) $ 16,719 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 and consisted of the following for the periods presented: For the year ended December 31, Derivatives not designated as hedging instruments 2017 2016 2015 (in thousands) Beginning fair value of commodity derivative instruments $ (16,719 ) $ 64,534 $ 37,471 Gain (loss) on oil derivative instruments (5,091 ) (15,998 ) 57,681 Gain (loss) on natural gas derivative instruments 31,993 (20,466 ) 32,607 Net cash received on settlements of oil derivative instruments (10,901 ) (27,450 ) (41,786 ) Net cash received on settlements of natural gas derivative instruments (4,310 ) (17,339 ) (21,439 ) Net change in fair value of commodity derivative instruments 11,691 (81,253 ) 27,063 Ending fair value of commodity derivative instruments $ (5,028 ) $ (16,719 ) $ 64,534 The Partnership had the following open derivative contracts for oil as of December 31, 2017 : Volume (Bbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2018 First quarter 729,000 $ 54.36 $ 52.09 $ 57.15 Second quarter 736,000 54.33 52.09 56.75 Third quarter 744,000 54.35 51.85 55.87 Fourth quarter 749,000 54.24 51.85 55.87 2019 First quarter 165,000 $ 53.58 $ 52.82 $ 54.02 Second quarter 165,000 53.58 52.82 54.02 Third quarter 165,000 53.58 52.82 54.02 Fourth quarter 165,000 53.58 52.82 54.02 The Partnership had the following open derivative contracts for natural gas as of December 31, 2017 : Volume (MMBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2018 First quarter 13,590,000 $ 3.06 $ 2.96 $ 3.45 Second quarter 13,660,000 3.02 2.86 3.23 Third quarter 13,600,000 3.01 2.90 3.23 Fourth quarter 13,630,000 3.01 2.90 3.23 2019 First quarter 3,600,000 2.91 2.90 2.93 Second quarter 3,600,000 2.91 2.90 2.93 Third quarter 3,600,000 2.91 2.90 2.93 Fourth quarter 3,600,000 2.91 2.90 2.93 Subsequent to December 31, 2017, the Partnership entered into oil derivative contracts for 35,000 barrels per month beginning February 2018 through December 2018 and 60,000 barrels per month in 2019 at weighted average prices of $61.85 and $57.58 , respectively.

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurement	FAIR VALUE MEASUREMENTS 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, Fair Value Measurement, 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, 2017 and 2016 . The carrying value of our cash and cash equivalents, receivables and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of December 31, 2017 and 2016 approximated the fair value due to variable market rates of interest. These debt 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. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of commodity derivative financial 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 – Commodity Derivative 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, 2017 Financial Assets Commodity derivative instruments $ — $ 12,105 $ — $ (11,648 ) $ 457 Financial Liabilities Commodity derivative instruments — 17,133 — (11,648 ) 5,485 As of December 31, 2016 Financial Assets Commodity derivative instruments $ — $ 3,879 $ — $ (3,879 ) $ — Financial Liabilities Commodity derivative instruments — 20,598 — (3,879 ) 16,719 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 and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are prepared by estimating discounted cash flow projections. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership's fair value assessments for recent acquisitions are included in Note 4 — Oil and Natural Gas Properties Acquisitions. Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate. 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, 2017 and 2016 . 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 1 Value 1 Impairment (In thousands) Year Ended December 31, 2017 Impaired oil and natural gas properties $ — $ — $ — $ — $ — Year Ended December 31, 2016 Impaired oil and natural gas properties $ — $ — $ 3,042 $ 9,817 $ 6,775 Year Ended December 31, 2015 Impaired oil and natural gas properties $ — $ — $ 156,689 $ 406,258 $ 249,569 1 Amounts represent fair value and net book value at the date of assessment.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Significant Customers	SIGNIFICANT CUSTOMERS The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. XTO Energy Inc., a subsidiary of Exxon Mobil Corporation ("Exxon"), represented approximately 21% of total revenue for the year ended December 31, 2017 . Exxon represented approximately 11% of total revenue for the year ended December 31, 2016 . No customer represented 10% or more of total revenue for the year ended December 31, 2015 . 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 Facility

Credit Facility	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Credit Facility	CREDIT FACILITY The Partnership maintains a secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has a maximum credit amount of $ 1.0 billion . The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Drawings on the Credit Facility are used for the acquisition of oil and natural gas properties and for other general business purposes. Effective April 15, 2016, the borrowing base was $450.0 million . The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million , which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $ 550.0 million . On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swingline facility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. There was no change to the borrowing base. The Credit Facility now terminates on November 1, 2022. Prior to October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 1.50% and 2.50% , or Prime Rate plus a margin between 0.50% and 1.50% , with the margin depending on the borrowing base utilization percentage of the loan. The Prime Rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. Effective October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 2.00% and 3.00% , or the Prime Rate plus a margin between 1.00% and 2.00% , with the margin depending on the borrowing base utilization of the loan. The weighted-average interest rate of the Credit Facility was 4.06% and 3.26% as of December 31, 2017 and 2016 , 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 Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility 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, 2017 , the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was $388.0 million and $ 316.0 million at December 31, 2017 and 2016 , respectively. The unused portion of the available borrowings under the Credit Facility were $162.0 million and $184.0 million at December 31, 2017 and 2016 , respectively.

Incentive Compensation

Incentive Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Incentive Compensation	INCENTIVE COMPENSATION Overview The Board of the Partnership’s general partner established 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 and subordinated units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vesting terms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof. 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 may also provide from time to time short-term and long-term cash incentive and retention awards annually for its directors, executive officers and certain other employees. Certain employees are entitled to receive cash bonuses based on service criteria over a four -year requisite service period ending in 2019. Payments are disbursed as vesting is attained on a graded annual basis. The last grant of such cash awards with graded vesting requirements was made in 2016 and extends through December 31, 2019. Restricted Unit Awards Restricted common units in the Predecessor outstanding as of the date of the IPO were converted into restricted common and subordinated units of the Partnership in connection with the IPO. The converted restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. 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 made by the Partnership. Non-employee directors of the Partnership’s general partner receive compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service. In conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the executive officers of the Partnership's general partner, certain other employees, and each of the non-employee directors of the Partnership’s general partner. The grants included restricted common units subject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements through March 15, 2019. The holders of restricted common unit awards have all of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method. The Compensation Committee of the Board (the "Compensation Committee") approved a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees. The grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020. 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. In April 2016, the Compensation Committee approved a resolution to change the form of settlement of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016 and the remaining unamortized expense of the awards will be amortized as equity-settled liabilities. Additionally, in January of each year, non-employee directors on the Board receive fully vested common units for their service in the previous year. The following table summarizes information about restricted units for the year ended December 31, 2017 . Units Weighted-Average Grant-Date Fair Value per Unit Common Subordinated Common Subordinated Unvested at December 31, 2016 1,271,215 163,041 $ 15.29 $ 18.97 Granted 901,910 — 18.48 — Vested (602,764 ) (103,912 ) 15.13 19.35 Converted — — — — Forfeited (28,303 ) — 17.64 — Unvested at December 31, 2017 1,542,058 59,129 16.72 18.30 The weighted-average grant-date fair value per unit for unit-based awards was $ 18.48 , $ 10.09 , and $ 18.79 for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $ 15.7 million and $ 0.2 million, respectively, as of December 31, 2017 , which the Partnership expects to recognize over a weighted-average period of 1.65 years and 0.2 years for common units and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2017 , 2016 , and 2015 was $25.1 million , $11.9 million , and $9.4 million , respectively. There were no cash payments made for vested units during the years ended December 31, 2017 , 2016 and 2015 . Performance Unit Awards The Compensation Committee also approved grants of 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 three calendar year performance periods commencing January 1 of the first calendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metrics are achieved. 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 probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight line attribution methods, depending on the terms of the award. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital. The Compensation Committee also approved dollar-value targets for performance-based short-term incentive compensation for executive officers and certain other employees of the Partnership. The Partnership expects to ultimately settle the authorized awards, at the end of the annual performance period, in common units. The following table summarizes information about performance units for the year ended December 31, 2017 . Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2016 1,156,419 $ 14.94 Granted 438,288 17.99 Vested — — Forfeited (137,351 ) 18.60 Unvested at December 31, 2017 1,457,356 15.51 Unrecognized compensation cost associated with performance unit awards was $10.1 million as of December 31, 2017 , which the Partnership expects to recognize over a weighted-average period of 1.54 years . 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, 2017 , 2016 , and 2015 . Year Ended December 31, Incentive compensation expense 2017 2016 2015 (In thousands) Cash — long-term incentive plan $ 1,412 $ 2,725 $ 15,064 Equity-based compensation — restricted common and subordinated units 13,476 13,408 10,137 Equity-based compensation — restricted performance units 17,367 18,518 4,743 Board of Directors incentive plan 2,202 2,012 3,120 Total incentive compensation expense $ 34,457 $ 36,663 $ 33,064

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS Black Stone Natural Resources Management Company, a subsidiary of 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 , $0.5 million , and $0.6 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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 2021. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $2.5 million , $1.9 million , and $1.8 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. 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 as of December 31, 2017: Year Ending December 31, (in thousands) 2018 $ 1,654 2019 38 2020 16 2021 — Total $ 1,708 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. Put Option Related to Noble Acquisition By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2017, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded. 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, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations.

Preferred Units

Preferred Units	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Redeemable Preferred Units	PREFERRED UNITS Series A Redeemable Preferred Units The Partnership had 26,363 and 52,691 Series A redeemable preferred units outstanding with a carrying value of $27.0 million and $54.0 million as of December 31, 2017 and 2016, respectively. The aforementioned amounts include accrued distributions of $0.7 million and $1.3 million as of December 31, 2017 and 2016, respectively. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The Series A redeemable preferred units are entitled to an annual distribution of 10% , payable on a quarterly basis in arrears. Prior to liquidation of the Partnership, and while any of the Series A redeemable preferred units remain outstanding, cash or other property of the Partnership will be distributed 100% to the Series A redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each Series A redeemable preferred unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero. Distributions in excess of the aggregate Unpaid Preferred Yield will be distributed 100% to common and subordinated unitholders, until there has been distributed an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common and subordinated units as of the first day of such calendar year. Any additional distributions shall be distributed to the common and subordinated unitholders, on the one hand, and the Series A redeemable preferred unitholders, on the other hand, pro rata on an as-is-converted basis. The terms “Interest Fair Market Value,” “Preferred Yield,” and “Unpaid Preferred Yield” have the following meanings: “Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a common unit or subordinated unit, as applicable, if (a) all of the Series A redeemable preferred units were converted into or exchanged or exercised for common units and, during the subordination period, subordinated units, (b) the fair market value of the assets of the Partnership in excess of its liabilities as of the date of determination of Interest Fair Market Value equaled the Value (as defined in the partnership agreement) as of such date, adjusted to reflect any increases in equity value resulting from the deemed conversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in the partnership agreement), as so adjusted, were distributed to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement. “Preferred Yield” means a yield on the outstanding Series A redeemable preferred units equivalent to a 10% per annum interest rate (subject to adjustment following certain events of default by the Partnership) on an initial investment of $1,000, calculated based on a 365-day year and compounded quarterly. “Unpaid Preferred Yield” means, with respect to each Series A redeemable preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a) the cumulative Preferred Yield from the closing of the IPO through the date established, over (b) the cumulative amount of distributions made as of the date established in respect of the Series A redeemable preferred unit. The Series A redeemable preferred units are convertible into common and subordinated units at the option of the Series A redeemable preferred unitholders. The Series A 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 Series A redeemable preferred unitholders can elect to have the Partnership redeem, at face value, up to 26,363 redeemable preferred units as of December 31, 2017. The Partnership shall have the right, at its sole option, to redeem an amount of Series A redeemable preferred units equal to the units being redeemed by an owner of Series A redeemable preferred units on each December 31. Any amount of a given year’s Series A redeemable preferred units eligible for redemption not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 in the following year. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically convert to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million , including accrued unpaid yield. For the year ended December 31, 2017, 6,624 Series A redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. For the year ended December 31, 2016, 18,461 Series A redeemable preferred units were redeemed for $19.0 million , including accrued unpaid yield. For the year ended December 31, 2016, 6,064 Series A redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjusted basis. For the year ended December 31, 2015, 39,240 Series A redeemable preferred units totaling $39.2 million were converted into the equivalent of 1,190,664 common units and 1,559,502 subordinated units on an adjusted basis. On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding Series A redeemable preferred units at par value plus unpaid accrued yield. The tender offer expired on December 10, 2015 . The Partnership purchased and canceled 40,747 Series A 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. Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the "Purchaser" for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million . The Series B cumulative convertible preferred units are entitled to an annual distribution of 7% , payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926 . The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926 , adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $295.4 million , including accrued distributions of $1.9 million , as of December 31, 2017. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheet since redemption is outside the control of the Partnership.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Unit	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 Series A redeemable preferred units could be converted into 0.8 million common units and 1.1 million subordinated units as of December 31, 2017 . The Series B cumulative convertible preferred units could be converted into 1.6 million weighted average common units as of December 31, 2017 . At December 31, 2017 , if the outstanding Series A redeemable preferred units were converted to common and subordinated units, and the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive. Therefore, the Series A redeemable preferred units and the Series B cumulative convertible preferred units are not included in the diluted EPU calculations. 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, 2017 , 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 anti-dilutive. The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2017 2016 2015 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 157,153 $ 20,188 $ (101,305 ) Net loss attributable to Predecessor — — (450 ) Net income attributable to noncontrolling interests subsequent to initial public offering 34 12 1,260 Distributions on Series A redeemable preferred units subsequent to initial public offering (3,117 ) (5,763 ) (7,522 ) Distributions on Series B cumulative convertible preferred units $ (1,925 ) — — NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING $ 152,145 $ 14,437 $ (108,017 ) ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO: General partner interest $ — $ — $ — Common units 98,389 24,669 (54,326 ) Subordinated units 53,756 (10,232 ) (53,691 ) $ 152,145 $ 14,437 $ (108,017 ) NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 1.01 $ 0.26 $ (0.56 ) Weighted average common units outstanding (basic) 97,400 96,073 96,182 Per subordinated unit (basic) $ 0.56 $ (0.11 ) $ (0.56 ) Weighted average subordinated units outstanding (basic) 95,149 95,138 95,057 Per common unit (diluted) $ 1.01 $ 0.26 $ (0.56 ) Weighted average common units outstanding (diluted) 97,400 96,243 96,182 Per subordinated unit (diluted) $ 0.56 $ (0.11 ) $ (0.56 ) Weighted average subordinated units outstanding (diluted) 95,149 95,138 95,057

Common and Subordinated Units

Common and Subordinated Units	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Common and Subordinated Units	COMMON AND SUBORDINATED UNITS Common and Subordinated Units The common units and subordinated units represent limited partner interests in the Partnership. The holders of common units, subordinated units, Series A redeemable preferred units, and Series B cumulative convertible preferred units are holders of separate classes of limited partner interests in the Partnership. The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control may not vote on any matter. The holders of common units and subordinated units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units under the partnership agreement. The partnership agreement generally provides that any distributions will be paid each quarter during the subordination period (as defined in our partnership agreement) in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments; • second , to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and • third , to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions to common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. Common Unit Repurchase Program On March 4, 2016, the Board of the Partnership's general partner authorized the repurchase of up to $50.0 million in common units through a program that terminated on September 15, 2016. The repurchase program authorized the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership repurchased a total of 1.3 million common units for an aggregate cost of $20.2 million . The repurchase program was funded from the Partnership's cash on hand or availability on the Credit Facility. Repurchased common units were canceled.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS On February 9, 2018, the Board approved a distribution for the period October 1, 2017 to December 31, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions were paid on February 27, 2018 to unitholders of record at the close of business on February 20, 2018. Subsequent to December 31, 2017, the Partnership entered into oil derivative contracts for 35,000 barrels per month beginning February 2018 through December 2018 and 60,000 barrels per month in 2019 at weighted average prices of $61.85 and $57.58 , respectively.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Disclosure (Unaudited)	12 Months Ended
	Dec. 31, 2017
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 U.S. 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, 2017 2016 2015 (in thousands) Acquisition Costs of Properties: 1 Proved $ 96,596 $ 40,242 $ 2,302 Unproved 383,535 100,888 60,994 Exploration Costs 618 645 2,592 Development Costs 81,056 73,316 60,056 Total $ 561,805 $ 215,091 $ 125,944 1. See Note 4 – Oil and Natural Gas Properties 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, 2017 2016 (in thousands) Proved properties $ 2,258,893 $ 2,091,337 Unproved properties 988,720 605,736 Total 3,247,613 2,697,073 Accumulated depreciation, depletion, amortization, and impairment (1,766,842 ) (1,652,930 ) Oil and natural gas properties, net $ 1,480,771 $ 1,044,143 Oil and Natural Gas Reserve Information 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, 2014 17,067 204,256 51,109 Revisions of previous estimates 1 (197 ) (17,043 ) (3,037 ) Purchases of minerals in place 2 8 367 69 Extensions, discoveries and other additions 3 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 Revisions of previous estimates 1 3,007 29,024 7,844 Purchases of minerals in place 4 1,322 5,683 2,269 Extensions, discoveries and other additions 5 1,877 79,455 15,120 Production (3,680 ) (47,498 ) (11,596 ) Net proved reserves at December 31, 2016 18,368 270,339 63,425 Revisions of previous estimates 1 (1,234 ) 21,067 2,277 Purchases of minerals in place 6 2,267 30,250 7,309 Extensions, discoveries and other additions 7 2,050 38,397 8,449 Production (3,552 ) (59,779 ) (13,515 ) Net proved reserves at December 31, 2017 17,899 300,274 67,945 Net Proved Developed Reserves 8 December 31, 2015 15,497 174,555 44,590 December 31, 2016 18,150 223,057 55,327 December 31, 2017 17,891 233,017 56,727 Net Proved Undeveloped Reserves 9 December 31, 2015 345 29,120 5,198 December 31, 2016 218 47,282 8,098 December 31, 2017 8 67,257 11,218 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 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. 3 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. 4 Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays. 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 the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins. 7 Includes extensions and additions related to drilling activities within multiple basins. 8 Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. 9 As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests. Standardized Measure of Discounted Future Net Cash Flows 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, 2017 2016 2015 (in thousands) Future cash inflows $ 1,643,582 $ 1,267,179 $ 1,211,290 Future production costs (211,064 ) (193,749 ) (205,861 ) Future development costs (70,111 ) (36,509 ) (84,746 ) Future income tax expense (2,655 ) (3,516 ) — Future net cash flows (undiscounted) 1,359,752 1,033,405 920,683 Annual discount 10% for estimated timing (497,103 ) (430,390 ) (365,711 ) Total 1 $ 862,649 $ 603,015 $ 554,972 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million , $0.6 million , and $0.7 million for December 31, 2017, 2016, and 2015, 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, 2017 2016 2015 (in thousands) Standardized measure, beginning of year $ 603,015 $ 554,972 $ 1,143,094 Sales, net of production costs (295,941 ) (210,354 ) (222,206 ) Net changes in prices and production costs related to future production 169,608 (81,456 ) (621,065 ) Extensions, discoveries and improved recovery, net of future production and development costs 113,199 86,606 165,020 Previously estimated development costs incurred during the period 11,118 28,909 7,084 Revisions of estimated future development costs 2,653 — 669 Revisions of previous quantity estimates, net of related costs 86,228 147,507 (67,911 ) Accretion of discount 60,512 55,662 114,309 Purchases of reserves in place, less related costs 107,891 34,751 584 Other 4,366 (13,582 ) 35,394 Net increase (decrease) in standardized measures 259,634 48,043 (588,122 ) Standardized measure, end of year $ 862,649 $ 603,015 $ 554,972 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, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information-Unaudited	Selected Quarterly Financial Information—Unaudited Quarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter 2 (In thousands, except for per unit data) 2017 Total revenue $ 124,582 $ 120,524 $ 89,111 $ 95,442 Income (loss) from operations 65,015 57,840 26,216 23,013 Net income (loss) 61,583 54,174 22,034 19,362 Net income (loss) attributable to the general partner and common and subordinated units 60,460 53,518 21,388 16,779 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) 0.37 0.33 0.16 0.15 Per subordinated unit (basic) 0.26 0.22 0.05 0.03 Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) 0.37 0.33 0.16 0.15 Per subordinated unit (diluted) 0.26 0.22 0.05 0.03 Cash distributions declared and paid per limited partner unit Per common unit $ 0.2875 $ 0.2875 $ 0.3125 $ 0.3125 Per subordinated unit $ 0.1838 $ 0.1838 $ 0.2088 $ 0.2088 Total assets $ 1,199,722 $ 1,250,086 $ 1,246,070 $ 1,576,451 Long-term debt 388,000 393,000 362,000 388,000 Total mezzanine equity 34,145 27,085 27,092 322,422 2016 Total revenue $ 64,381 $ 40,569 $ 99,171 $ 56,712 Net income (loss) 11,610 (19,478 ) 39,316 (3,979 ) Income (loss) from operations 10,749 (20,810 ) 37,535 (7,286 ) Net income (loss) attributable to the general partner and common and subordinated units 8,943 (22,111 ) 36,219 (8,614 ) Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) 0.09 (0.08 ) 0.24 0.01 Per subordinated unit (basic) 0.01 (0.15 ) 0.14 (0.11 ) Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) 0.09 (0.08 ) 0.24 0.01 Per subordinated unit (diluted) 0.01 (0.15 ) 0.14 (0.11 ) Cash distributions declared per limited partner unit Per common unit $ 0.2625 $ 0.2625 $ 0.2875 $ 0.2875 Per subordinated unit $ 0.1838 $ 0.1838 $ 0.1838 $ 0.1838 Total assets 1,045,843 1,126,830 1,137,232 1,128,827 Long-term debt 116,000 285,000 299,000 316,000 Total mezzanine equity 54,001 54,001 54,015 54,015 1 See Note 13 – Earnings Per Unit in the consolidated financial statements. 2 Reported volumes in the fourth quarter of 2016 were negatively impacted by production shut-ins estimated at 1.0 MBoe/d for the quarter related to offset completion work and processing plant downtime in the Haynesville Shale.

At-The-Market Offering Program

At-The-Market Offering Program (Notes)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
AT-THE-MARKET OFFERING PROGRAM	AT-THE-MARKET OFFERING PROGRAM On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to $100,000,000 . Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange. Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent. The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility. Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions. Through December 31, 2017 , the Partnership sold 2.0 million common units under the ATM Program for net proceeds of $32.5 million .

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Use of estimates	Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those 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, and 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 estimates 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 commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the 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 oil or natural gas 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 predicted accurately, actual results could differ significantly from estimates.
Cash and cash equivalents	Cash and Cash Equivalents The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts Receivable The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.
Commodity derivative financial instruments	Commodity Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. 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 sheets. 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 derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.
Concentration of credit risk	Concentration of Credit Risk Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. The Partnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 7 – Significant Customers for further discussion.
Oil and natural gas properties	Oil and Natural Gas Properties The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. 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 cost. The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit. As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, 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. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. 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.
Other property and equipment	Other Property and Equipment Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years.
Repairs and maintenance	Repairs and Maintenance The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.
Debt issuance costs	Debt Issuance Costs Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated.
Asset retirement obligations	Asset Retirement Obligations Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.
Revenue recognition	Revenue Recognition The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. 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, 2017 and 2016 . 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 include mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to 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 The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxes are not material. 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. 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 The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31, 2017 and 2016 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurements for further discussion.
Incentive compensation	Incentive Compensation Incentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant date fair values. Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units 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. Incentive compensation expense is charged to general and administrative expense on the consolidated statements of operations. See Note 9 – Incentive Compensation for additional discussion.
New accounting pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersede ASC 605, Revenue Recognition . Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures. The Partnership has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership intends to use the modified retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018, and does not anticipate recording or disclosing any material transition adjustments upon adoption. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership intends to use the retrospective transition method upon adoption of the new guidance on the effective date of January 1, 2018 and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership will adopt the new guidance prospectively as of the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met: • The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified. • The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified. • The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Partnership will adopt the new guidance prospectively to all awards modified on or after the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures.
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.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consisted of the following as of December 31, 2017 and 2016: As of December 31, 2017 2016 Accrued liabilities: (in thousands) Accrued capital expenditures $ 28,711 $ 17,775 Accrued incentive compensation 16,503 20,898 Accrued property taxes 4,090 3,175 Accrued other 3,327 9,104 Total accrued liabilities $ 52,631 $ 50,952

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
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 periods presented: For the year ended December 31, 2017 2016 (in thousands) Beginning asset retirement obligations $ 13,350 $ 10,585 Liabilities incurred 308 2,009 Liabilities settled (228 ) (317 ) Accretion expense 1,026 892 Revisions in estimated costs 83 181 Dispositions (30 ) — Ending asset retirement obligations $ 14,509 $ 13,350 Current asset retirement obligations $ 417 $ — Non-current asset retirement obligations $ 14,092 $ 13,350

Oil and Natural Gas Propertie28

Oil and Natural Gas Properties Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued Acquisition-Related Costs 1 (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 27,380 $ 12,026 $ 1,162 June 5,006 45,477 — 50,483 4,802 45,681 1,481 August 3,277 9,984 — 13,261 4,289 8,972 107 September 3,120 — — 3,120 3,120 — — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 39,591 $ 66,679 $ 2,750 1 Acquisition-related costs were expensed and included in the general and administrative expense line item of the 2017 consolidated statement of operations.
Schedule of Pro Forma Information From Business Acquisition	The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016. For the Year Ended December 31, 2017 2016 (in thousands, except per unit amounts) Revenue and other income $ 468,103 $ 288,772 Net income (loss) $ 178,970 $ 33,264 Net income (loss) attributable to noncontrolling interests 34 12 Distributions on Series A redeemable preferred units (3,117 ) (5,763 ) Distributions on Series B cumulative convertible preferred units (21,000 ) (21,000 ) Net income (loss) attributable to the general partner and common and subordinated units $ 154,887 $ 6,513 Allocation of net income (loss): General partner interest — — Common units 99,776 20,696 Subordinated units 55,111 (14,183 ) $ 154,887 $ 6,513 Net income (loss) attributable to limited partners per common and subordinated unit: Per common unit (basic) $ 1.02 $ 0.22 Per subordinated unit (basic) $ 0.58 $ (0.15 ) Per common unit (diluted) $ 1.02 $ 0.22 Per subordinated unit (diluted) $ 0.58 $ (0.15 )
Noble Acquisition
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Cash Consideration Paid Acquisition-Related Costs 1 Proved Unproved Net Working Capital Total Fair Value (in thousands) Noble Assets $ 68,877 $ 259,749 $ 5,917 $ 334,543 $ 334,543 $ 247 1 Acquisition-related costs were expensed and included in the general and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.
East Texas
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	Assets Acquired Consideration Paid Unproved Cash Fair Value of Common Units Issued (in thousands) Q1 2017 $ 21,189 $ 21,017 $ 172 Q2 2017 13,329 13,329 — Q3 2017 19,946 15,205 4,741 Q4 2017 2,267 2,137 130 Total acquired $ 56,731 $ 51,688 $ 5,043
2016 Acquisitions
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes the fair value assigned to the properties acquired: Assets Acquired Cash Consideration Paid Proved Unproved Net Working Capital ARO Total Fair Value (in thousands) June 2016 $ 39,735 $ 79,827 $ 2,064 $ (50 ) $ 121,576 $ 121,576

Commodity Derivative Financia29

Commodity Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative [Line Items]
Summary of Fair Value and Classification of Derivative Instruments	The tables below summarize the fair value and classification of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at December 31, 2017 and 2016: As of December 31, 2017 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 $ 10,713 $ (10,619 ) $ 94 Long-term asset Deferred charges and other long-term assets 1,392 (1,029 ) 363 Total assets $ 12,105 $ (11,648 ) $ 457 Liabilities: Current liability Commodity derivative liabilities $ 14,841 $ (10,619 ) $ 4,222 Long-term liability Commodity derivative liabilities 2,292 (1,029 ) 1,263 Total liabilities $ 17,133 $ (11,648 ) $ 5,485 As of December 31, 2016 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 3,879 $ (3,879 ) $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ 3,879 $ (3,879 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 20,116 $ (3,879 ) $ 16,237 Long-term liability Commodity derivative liabilities 482 — 482 Total liabilities $ 20,598 $ (3,879 ) $ 16,719
Changes in Fair Value of Company's Commodity Derivative Instruments	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 and consisted of the following for the periods presented: For the year ended December 31, Derivatives not designated as hedging instruments 2017 2016 2015 (in thousands) Beginning fair value of commodity derivative instruments $ (16,719 ) $ 64,534 $ 37,471 Gain (loss) on oil derivative instruments (5,091 ) (15,998 ) 57,681 Gain (loss) on natural gas derivative instruments 31,993 (20,466 ) 32,607 Net cash received on settlements of oil derivative instruments (10,901 ) (27,450 ) (41,786 ) Net cash received on settlements of natural gas derivative instruments (4,310 ) (17,339 ) (21,439 ) Net change in fair value of commodity derivative instruments 11,691 (81,253 ) 27,063 Ending fair value of commodity derivative instruments $ (5,028 ) $ (16,719 ) $ 64,534
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, 2017 : Volume (Bbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2018 First quarter 729,000 $ 54.36 $ 52.09 $ 57.15 Second quarter 736,000 54.33 52.09 56.75 Third quarter 744,000 54.35 51.85 55.87 Fourth quarter 749,000 54.24 51.85 55.87 2019 First quarter 165,000 $ 53.58 $ 52.82 $ 54.02 Second quarter 165,000 53.58 52.82 54.02 Third quarter 165,000 53.58 52.82 54.02 Fourth quarter 165,000 53.58 52.82 54.02 The Partnership had the following open derivative contracts for natural gas as of December 31, 2017 : Volume (MMBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2018 First quarter 13,590,000 $ 3.06 $ 2.96 $ 3.45 Second quarter 13,660,000 3.02 2.86 3.23 Third quarter 13,600,000 3.01 2.90 3.23 Fourth quarter 13,630,000 3.01 2.90 3.23 2019 First quarter 3,600,000 2.91 2.90 2.93 Second quarter 3,600,000 2.91 2.90 2.93 Third quarter 3,600,000 2.91 2.90 2.93 Fourth quarter 3,600,000 2.91 2.90 2.93

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 Financial Assets Commodity derivative instruments $ — $ 12,105 $ — $ (11,648 ) $ 457 Financial Liabilities Commodity derivative instruments — 17,133 — (11,648 ) 5,485 As of December 31, 2016 Financial Assets Commodity derivative instruments $ — $ 3,879 $ — $ (3,879 ) $ — Financial Liabilities Commodity derivative instruments — 20,598 — (3,879 ) 16,719
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 1 Value 1 Impairment (In thousands) Year Ended December 31, 2017 Impaired oil and natural gas properties $ — $ — $ — $ — $ — Year Ended December 31, 2016 Impaired oil and natural gas properties $ — $ — $ 3,042 $ 9,817 $ 6,775 Year Ended December 31, 2015 Impaired oil and natural gas properties $ — $ — $ 156,689 $ 406,258 $ 249,569 1 Amounts represent fair value and net book value at the date of assessment.

Incentive Compensation (Tables)

Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Information about Restricted Units	The following table summarizes information about restricted units for the year ended December 31, 2017 . Units Weighted-Average Grant-Date Fair Value per Unit Common Subordinated Common Subordinated Unvested at December 31, 2016 1,271,215 163,041 $ 15.29 $ 18.97 Granted 901,910 — 18.48 — Vested (602,764 ) (103,912 ) 15.13 19.35 Converted — — — — Forfeited (28,303 ) — 17.64 — Unvested at December 31, 2017 1,542,058 59,129 16.72 18.30
Summary of Information about Performance Units	The following table summarizes information about performance units for the year ended December 31, 2017 . Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2016 1,156,419 $ 14.94 Granted 438,288 17.99 Vested — — Forfeited (137,351 ) 18.60 Unvested at December 31, 2017 1,457,356 15.51
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, 2017 , 2016 , and 2015 . Year Ended December 31, Incentive compensation expense 2017 2016 2015 (In thousands) Cash — long-term incentive plan $ 1,412 $ 2,725 $ 15,064 Equity-based compensation — restricted common and subordinated units 13,476 13,408 10,137 Equity-based compensation — restricted performance units 17,367 18,518 4,743 Board of Directors incentive plan 2,202 2,012 3,120 Total incentive compensation expense $ 34,457 $ 36,663 $ 33,064

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
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 as of December 31, 2017: Year Ending December 31, (in thousands) 2018 $ 1,654 2019 38 2020 16 2021 — Total $ 1,708

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 157,153 $ 20,188 $ (101,305 ) Net loss attributable to Predecessor — — (450 ) Net income attributable to noncontrolling interests subsequent to initial public offering 34 12 1,260 Distributions on Series A redeemable preferred units subsequent to initial public offering (3,117 ) (5,763 ) (7,522 ) Distributions on Series B cumulative convertible preferred units $ (1,925 ) — — NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING $ 152,145 $ 14,437 $ (108,017 ) ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO: General partner interest $ — $ — $ — Common units 98,389 24,669 (54,326 ) Subordinated units 53,756 (10,232 ) (53,691 ) $ 152,145 $ 14,437 $ (108,017 ) NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 1.01 $ 0.26 $ (0.56 ) Weighted average common units outstanding (basic) 97,400 96,073 96,182 Per subordinated unit (basic) $ 0.56 $ (0.11 ) $ (0.56 ) Weighted average subordinated units outstanding (basic) 95,149 95,138 95,057 Per common unit (diluted) $ 1.01 $ 0.26 $ (0.56 ) Weighted average common units outstanding (diluted) 97,400 96,243 96,182 Per subordinated unit (diluted) $ 0.56 $ (0.11 ) $ (0.56 ) Weighted average subordinated units outstanding (diluted) 95,149 95,138 95,057

Supplemental Oil and Natural 34

Supplemental Oil and Natural Gas Disclosure (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 (in thousands) Acquisition Costs of Properties: 1 Proved $ 96,596 $ 40,242 $ 2,302 Unproved 383,535 100,888 60,994 Exploration Costs 618 645 2,592 Development Costs 81,056 73,316 60,056 Total $ 561,805 $ 215,091 $ 125,944 1. See Note 4 – Oil and Natural Gas Properties 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, 2017 2016 (in thousands) Proved properties $ 2,258,893 $ 2,091,337 Unproved properties 988,720 605,736 Total 3,247,613 2,697,073 Accumulated depreciation, depletion, amortization, and impairment (1,766,842 ) (1,652,930 ) Oil and natural gas properties, net $ 1,480,771 $ 1,044,143
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, 2014 17,067 204,256 51,109 Revisions of previous estimates 1 (197 ) (17,043 ) (3,037 ) Purchases of minerals in place 2 8 367 69 Extensions, discoveries and other additions 3 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 Revisions of previous estimates 1 3,007 29,024 7,844 Purchases of minerals in place 4 1,322 5,683 2,269 Extensions, discoveries and other additions 5 1,877 79,455 15,120 Production (3,680 ) (47,498 ) (11,596 ) Net proved reserves at December 31, 2016 18,368 270,339 63,425 Revisions of previous estimates 1 (1,234 ) 21,067 2,277 Purchases of minerals in place 6 2,267 30,250 7,309 Extensions, discoveries and other additions 7 2,050 38,397 8,449 Production (3,552 ) (59,779 ) (13,515 ) Net proved reserves at December 31, 2017 17,899 300,274 67,945 Net Proved Developed Reserves 8 December 31, 2015 15,497 174,555 44,590 December 31, 2016 18,150 223,057 55,327 December 31, 2017 17,891 233,017 56,727 Net Proved Undeveloped Reserves 9 December 31, 2015 345 29,120 5,198 December 31, 2016 218 47,282 8,098 December 31, 2017 8 67,257 11,218 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 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. 3 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. 4 Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays. 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 the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins. 7 Includes extensions and additions related to drilling activities within multiple basins. 8 Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. 9 As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2017 2016 2015 (in thousands) Future cash inflows $ 1,643,582 $ 1,267,179 $ 1,211,290 Future production costs (211,064 ) (193,749 ) (205,861 ) Future development costs (70,111 ) (36,509 ) (84,746 ) Future income tax expense (2,655 ) (3,516 ) — Future net cash flows (undiscounted) 1,359,752 1,033,405 920,683 Annual discount 10% for estimated timing (497,103 ) (430,390 ) (365,711 ) Total 1 $ 862,649 $ 603,015 $ 554,972 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million , $0.6 million , and $0.7 million for December 31, 2017, 2016, and 2015, 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, 2017 2016 2015 (in thousands) Standardized measure, beginning of year $ 603,015 $ 554,972 $ 1,143,094 Sales, net of production costs (295,941 ) (210,354 ) (222,206 ) Net changes in prices and production costs related to future production 169,608 (81,456 ) (621,065 ) Extensions, discoveries and improved recovery, net of future production and development costs 113,199 86,606 165,020 Previously estimated development costs incurred during the period 11,118 28,909 7,084 Revisions of estimated future development costs 2,653 — 669 Revisions of previous quantity estimates, net of related costs 86,228 147,507 (67,911 ) Accretion of discount 60,512 55,662 114,309 Purchases of reserves in place, less related costs 107,891 34,751 584 Other 4,366 (13,582 ) 35,394 Net increase (decrease) in standardized measures 259,634 48,043 (588,122 ) Standardized measure, end of year $ 862,649 $ 603,015 $ 554,972

Selected Quarterly Financial 35

Selected Quarterly Financial Information—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
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 2 (In thousands, except for per unit data) 2017 Total revenue $ 124,582 $ 120,524 $ 89,111 $ 95,442 Income (loss) from operations 65,015 57,840 26,216 23,013 Net income (loss) 61,583 54,174 22,034 19,362 Net income (loss) attributable to the general partner and common and subordinated units 60,460 53,518 21,388 16,779 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) 0.37 0.33 0.16 0.15 Per subordinated unit (basic) 0.26 0.22 0.05 0.03 Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) 0.37 0.33 0.16 0.15 Per subordinated unit (diluted) 0.26 0.22 0.05 0.03 Cash distributions declared and paid per limited partner unit Per common unit $ 0.2875 $ 0.2875 $ 0.3125 $ 0.3125 Per subordinated unit $ 0.1838 $ 0.1838 $ 0.2088 $ 0.2088 Total assets $ 1,199,722 $ 1,250,086 $ 1,246,070 $ 1,576,451 Long-term debt 388,000 393,000 362,000 388,000 Total mezzanine equity 34,145 27,085 27,092 322,422 2016 Total revenue $ 64,381 $ 40,569 $ 99,171 $ 56,712 Net income (loss) 11,610 (19,478 ) 39,316 (3,979 ) Income (loss) from operations 10,749 (20,810 ) 37,535 (7,286 ) Net income (loss) attributable to the general partner and common and subordinated units 8,943 (22,111 ) 36,219 (8,614 ) Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) 0.09 (0.08 ) 0.24 0.01 Per subordinated unit (basic) 0.01 (0.15 ) 0.14 (0.11 ) Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) 0.09 (0.08 ) 0.24 0.01 Per subordinated unit (diluted) 0.01 (0.15 ) 0.14 (0.11 ) Cash distributions declared per limited partner unit Per common unit $ 0.2625 $ 0.2625 $ 0.2875 $ 0.2875 Per subordinated unit $ 0.1838 $ 0.1838 $ 0.1838 $ 0.1838 Total assets 1,045,843 1,126,830 1,137,232 1,128,827 Long-term debt 116,000 285,000 299,000 316,000 Total mezzanine equity 54,001 54,001 54,015 54,015 1 See Note 13 – Earnings Per Unit in the consolidated financial statements. 2 Reported volumes in the fourth quarter of 2016 were negatively impacted by production shut-ins estimated at 1.0 MBoe/d for the quarter related to offset completion work and processing plant downtime in the Haynesville Shale.

Business and Basis of Present36

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions	May 06, 2015USD ($)$ / sharesshares	Dec. 31, 2017basinstateshares	Dec. 31, 2015shares
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 | state		41
Number of onshore oil and natural gas producing basins | basin		64
Common Units
Limited Partners Capital Account [Line Items]
Issuance of common units for initial public offering, net of offering costs, units		2,002,000	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
Units conversion ratio split up as part of merger	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
Subordinated Units | Predecessor
Limited Partners Capital Account [Line Items]
Units exchanged in merger	95,057,312
Units conversion ratio as part of merger	12.9465
Units conversion ratio split up as part of merger	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 Policies - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion and amortization	$ 114,534	$ 102,487	$ 104,298
Impairment of oil and natural gas properties	0	6,775	249,569
Amortization expense for debt issue costs	900	900	900
Oil and Natural Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion and amortization	114,300	102,400	102,700
Proved Oil And Gas Properties [Member]
Summary Of Significant Accounting Polices [Line Items]
Impairment of oil and natural gas properties	0	4,900	127,800
Unproved Oil And Natural Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Impairment of oil and natural gas properties	0	1,900	121,800
Other Property and Equipment
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion and amortization	$ 200	$ 100	$ 1,600
Other Property and Equipment | Minimum
Summary Of Significant Accounting Polices [Line Items]
Other property and equipment, expected useful lives	3 years
Other Property and Equipment | Maximum
Summary Of Significant Accounting Polices [Line Items]
Other property and equipment, expected useful lives	7 years

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Total Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Accrued capital expenditures	$ 28,711	$ 17,775
Accrued incentive compensation	16,503	20,898
Accrued property taxes	4,090	3,175
Accrued other	3,327	9,104
TOTAL ACCRUED LIABILITIES	$ 52,631	$ 50,952

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 13,350	$ 10,585
Liabilities incurred	308	2,009
Liabilities settled	(228)	(317)
Accretion expense	1,026	892	$ 1,075
Revisions in estimated costs	83	181
Dispositions	(30)	0
Ending asset retirement obligations	14,509	13,350	$ 10,585
Current asset retirement obligations	417	0
Non-current asset retirement obligations	$ 14,092	$ 13,350

Oil and Natural Gas Propertie40

Oil and Natural Gas Properties Acquisitions - Additional Information (Details) $ in Thousands	Nov. 28, 2017USD ($)shares	Nov. 21, 2017well	Feb. 21, 2017wellphase	Dec. 31, 2017USD ($)awellstate	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs				$ 293,469	$ 0	$ 0
Asset acquisition payments to acquire oil mineral and royalty interests					1,200
Noble Acquisition
Business Acquisition [Line Items]
Royalty interests spread | state				20
Payments to acquire businesses, gross				$ 335,000
Pro Forma revenues				2,800
Purchase of mineral and royalty interest				$ 334,543
Permian Basin
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests					10,000
Purchase of mineral and royalty interest						51,700
Eagle Ford Shale Play
Business Acquisition [Line Items]
Purchase of mineral and royalty interest						9,700
Utica Shale And Marcellus Plays
Business Acquisition [Line Items]
Purchase of mineral and royalty interest						$ 1,800
Midland Basin
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests					$ 8,300
Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs	$ 300,000
Series B Cumulative Convertible Preferred Units | Noble Acquisition
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs	$ 300,000
Number of shares issued | shares	14,711,219
Senior Line of Credit | Revolving Credit Facility | Noble Acquisition
Business Acquisition [Line Items]
Maximum borrowing capacity	$ 35,000
Farmout Agreement | Angelina County, Texas
Business Acquisition [Line Items]
Ownership interest, acreage, percent			50.00%
Exploratory wells, expected to be drilled | well			18
Exploratory wells drilled | well				10
Exploratory wells, additional wells to be drilled | well			20
Asset acquisition, number of phases			3
Canaan Resource Partners | Farmout Agreement | Angelina County, Texas
Business Acquisition [Line Items]
Pro Forma revenues				$ 13,600
Asset acquisition, term of phase			2 years
Asset acquisition, option, number of additional phases | phase			2
Asset acquisition, funding requirements, drilling and completion costs, percent			80.00%
Asset acquisition, ownership interest in wells, percent			80.00%
Asset acquisition, ownership interest, gross, percent			40.00%
Asset acquisition,third phase, ownership interest In additional wells, percent			40.00%
Asset acquisition, third phase, ownership interest in additional wells, gross, percent			20.00%
Asset acquisition, third phase, funding requirements, drilling and completion costs, percent			40.00%
Pivotal | Farmout Agreement | San Augustine County, Texas
Business Acquisition [Line Items]
Pro Forma revenues				$ 5,600
Exploratory wells, expected to be drilled | well		80
Asset acquisition, term of phase		8 years
Asset acquisition, ownership interest in wells, percent		20.00%
Asset acquisition, ownership interest, gross, percent		10.00%
Asset acquisition, ownership interest, in wells operated by others, percent		100.00%
Minimum | Pivotal | Farmout Agreement | San Augustine County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		12.50%
Maximum | Pivotal | Farmout Agreement | San Augustine County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		25.00%
Mineral Acres | Noble Acquisition
Business Acquisition [Line Items]
Mineral interests and other non-cost bearing interests acquired, net | a				140,000
Overriding royalty interests, gross | a				1,100,000
Non-participating Royalty Interest | Noble Acquisition
Business Acquisition [Line Items]
Overriding royalty interests, gross | a				380,000
Overriding Royalty Interest | Noble Acquisition
Business Acquisition [Line Items]
Overriding royalty interests, gross | a				600,000

Oil and Natural Gas Propertie41

Oil and Natural Gas Properties Acquisitions - Pro Forma Information (Details) - Noble Acquisition - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenue and other income	$ 468,103	$ 288,772
Net income (loss)	178,970	33,264
Net income attributable to noncontrolling interests subsequent to initial public offering	34	12
Distributions on Series A redeemable preferred units	(3,117)	(5,763)
Distributions on Series B cumulative convertible preferred units	(21,000)	(21,000)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	154,887	6,513
Allocation of net income (loss):
General partner interest	0	0
Common Units
Allocation of net income (loss):
Allocation of loss	$ 99,776	$ 20,696
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit (basic) (in usd per share)	$ 1.02	$ 0.22
Per unit (diluted) (in usd per share)	$ 1.02	$ 0.22
Subordinated Units
Allocation of net income (loss):
Allocation of loss	$ 55,111	$ (14,183)
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per unit (basic) (in usd per share)	$ 0.58	$ (0.15)
Per unit (diluted) (in usd per share)	$ 0.58	$ (0.15)

Oil and Natural Gas Propertie42

Oil and Natural Gas Properties Acquisitions - Schedule of Fair Values of the Assets Acquired (Details) - USD ($) $ in Thousands	1 Months Ended				3 Months Ended				6 Months Ended	12 Months Ended
	Sep. 30, 2017	Aug. 31, 2017	Jun. 30, 2017	Jan. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 30, 2017
Business Acquisition [Line Items]
Proved										$ 96,596	$ 40,242	$ 2,302
Unproved										383,535	$ 100,888	$ 60,994
2017 Acquisitions
Business Acquisition [Line Items]
Proved	$ 3,120	$ 3,277	$ 5,006	$ 5,135						16,538
Unproved	0	9,984	45,477	34,008						89,469
Total Fair Value	3,120	13,261	50,483	39,406						106,270
Cash	3,120	4,289	4,802	27,380	$ 39,591	$ 3,120	$ 4,802			39,591
Net working capital	0	0	0	263						263
Acquisition-Related Costs	0	107	1,481	1,162						2,750
Fair Value of Common Units Issued	0	$ 8,972	45,681	$ 12,026						66,679
East Texas
Business Acquisition [Line Items]
Unproved					2,267	19,946	13,329	$ 21,189		56,731
Cash	$ 15,205		$ 13,329		51,688	15,205	13,329	21,017		51,688			$ 2,137
Fair Value of Common Units Issued					130	$ 4,741	$ 0	$ 172		5,043
Noble Acquisition
Business Acquisition [Line Items]
Proved										68,877
Unproved										259,749
Total Fair Value										334,543
Cash					$ 334,543					334,543
Net working capital										5,917
Acquisition-Related Costs										$ 247
2016 Acquisitions
Business Acquisition [Line Items]
Proved									$ 39,735
Unproved									79,827
Total Fair Value									121,576
Cash									121,576
Net working capital									2,064
ARO									$ (50)

Commodity Derivative Financia43

Commodity Derivative Financial Instruments - Additional Information (Details) $ in Millions	Dec. 31, 2017USD ($)counterparty
Derivative [Line Items]
Number Of counterparties	9
Senior Line of Credit
Derivative [Line Items]
Number Of counterparties	7
Fair value of risk exposure | $	$ 12.1

Commodity Derivative Financia44

Commodity Derivative Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	$ 12,105	$ 3,879
Effect of Counterparty Netting, Assets	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Assets	457	0
Gross Fair Value, Liabilities	17,133	20,598
Effect of Counterparty Netting, Liabilities	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	5,485	16,719
Commodity Derivative Assets, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	10,713	3,879
Effect of Counterparty Netting, Assets	(10,619)	(3,879)
Net Carrying Value on Balance Sheet, Assets	94	0
Deferred Charges and Other Long-term Assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	1,392	0
Effect of Counterparty Netting, Assets	(1,029)	0
Net Carrying Value on Balance Sheet, Assets	363	0
Commodity Derivative Liabilities, Current
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	14,841	20,116
Effect of Counterparty Netting, Liabilities	(10,619)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	4,222	16,237
Commodity Derivative Liabilities, Long-term
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	2,292	482
Effect of Counterparty Netting, Liabilities	(1,029)	0
Net Carrying Value on Balance Sheet, Liabilities	$ 1,263	$ 482

Commodity Derivative Financia45

Commodity Derivative Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	$ 26,902	$ (36,464)	$ 90,288
Net cash (received) paid on settlements of derivative instruments	(15,211)	(44,789)	(63,225)
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	(16,719)	64,534	37,471
Net change in fair value of commodity derivative instruments	11,691	(81,253)	27,063
Ending fair value of commodity derivative instruments	(5,028)	(16,719)	64,534
Oil | Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	(5,091)	(15,998)	57,681
Net cash (received) paid on settlements of derivative instruments	(10,901)	(27,450)	(41,786)
Natural Gas | Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	31,993	(20,466)	32,607
Net cash (received) paid on settlements of derivative instruments	$ (4,310)	$ (17,339)	$ (21,439)

Derivatives and Financial Instr

Derivatives and Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument - Swap Contracts - Swap bbl in Thousands, MMBTU in Thousands	2 Months Ended	12 Months Ended
	Feb. 27, 2018$ / bblbbl	Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl
Oil | Q1 2018
Derivative [Line Items]
Derivative Contract, Volume | bbl		729
Derivative Contract, Weighted Average Price		54.36
Derivative Contract, Price Range Low		52.09
Derivative Contract, Price Range High		57.15
Oil | Q2 2018
Derivative [Line Items]
Derivative Contract, Volume | bbl		736
Derivative Contract, Weighted Average Price		54.33
Derivative Contract, Price Range Low		52.09
Derivative Contract, Price Range High		56.75
Oil | Q3 2018
Derivative [Line Items]
Derivative Contract, Volume | bbl		744
Derivative Contract, Weighted Average Price		54.35
Derivative Contract, Price Range Low		51.85
Derivative Contract, Price Range High		55.87
Oil | Q4 2018
Derivative [Line Items]
Derivative Contract, Volume | bbl		749
Derivative Contract, Weighted Average Price		54.24
Derivative Contract, Price Range Low		51.85
Derivative Contract, Price Range High		55.87
Oil | Q1 2019
Derivative [Line Items]
Derivative Contract, Volume | bbl		165
Derivative Contract, Weighted Average Price		53.58
Derivative Contract, Price Range Low		52.82
Derivative Contract, Price Range High		54.02
Oil | Q2 2019
Derivative [Line Items]
Derivative Contract, Volume | bbl		165
Derivative Contract, Weighted Average Price		53.58
Derivative Contract, Price Range Low		52.82
Derivative Contract, Price Range High		54.02
Oil | Q3 2019
Derivative [Line Items]
Derivative Contract, Volume | bbl		165
Derivative Contract, Weighted Average Price		53.58
Derivative Contract, Price Range Low		52.82
Derivative Contract, Price Range High		54.02
Oil | Q4 2019
Derivative [Line Items]
Derivative Contract, Volume | bbl		165
Derivative Contract, Weighted Average Price		53.58
Derivative Contract, Price Range Low		52.82
Derivative Contract, Price Range High		54.02
Natural Gas | Q1 2018
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		13,590
Derivative Contract, Weighted Average Price | $ / MMBTU		3.06
Derivative Contract, Price Range Low | $ / MMBTU		2.96
Derivative Contract, Price Range High | $ / MMBTU		3.45
Natural Gas | Q2 2018
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		13,660
Derivative Contract, Weighted Average Price | $ / MMBTU		3.02
Derivative Contract, Price Range Low | $ / MMBTU		2.86
Derivative Contract, Price Range High | $ / MMBTU		3.23
Natural Gas | Q3 2018
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		13,600
Derivative Contract, Weighted Average Price | $ / MMBTU		3.01
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		3.23
Natural Gas | Q4 2018
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		13,630
Derivative Contract, Weighted Average Price | $ / MMBTU		3.01
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		3.23
Natural Gas | Q1 2019
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		3,600
Derivative Contract, Weighted Average Price | $ / MMBTU		2.91
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		2.93
Natural Gas | Q2 2019
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		3,600
Derivative Contract, Weighted Average Price | $ / MMBTU		2.91
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		2.93
Natural Gas | Q3 2019
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		3,600
Derivative Contract, Weighted Average Price | $ / MMBTU		2.91
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		2.93
Natural Gas | Q4 2019
Derivative [Line Items]
Derivative Contract, Volume | MMBTU		3,600
Derivative Contract, Weighted Average Price | $ / MMBTU		2.91
Derivative Contract, Price Range Low | $ / MMBTU		2.90
Derivative Contract, Price Range High | $ / MMBTU		2.93
Subsequent Event | Oil | February 2018 Through December 2018
Derivative [Line Items]
Derivative Contract, Volume | bbl	35
Derivative Contract, Weighted Average Price	61.85
Subsequent Event | Oil | FY 2019
Derivative [Line Items]
Derivative Contract, Volume | bbl	60
Derivative Contract, Weighted Average Price	57.58

Fair Value Measurement - Schedu

Fair Value Measurement - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	$ 12,105	$ 3,879
Effect of Counterparty Netting, Assets	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Assets	457	0
Gross Fair Value, Liabilities	17,133	20,598
Effect of Counterparty Netting, Liabilities	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	5,485	16,719
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of Counterparty Netting, Assets	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Assets	457	0
Effect of Counterparty Netting, Liabilities	(11,648)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	5,485	16,719
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	0	0
Gross Fair Value, Liabilities	0	0
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	12,105	3,879
Gross Fair Value, Liabilities	17,133	20,598
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	0	0
Gross Fair Value, Liabilities	$ 0	$ 0

Fair Value Measurement - Sche48

Fair Value Measurement - Schedule of Assets Measured at Fair Value on a Non-recurring Basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Impairment	$ 0	$ 6,775	$ 249,569
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	0	9,817	406,258
Impaired oil and natural gas properties, Impairment	0	6,775	249,569
Fair Value Measurements, Non-recurring Basis | Level 1
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	0	0	0
Fair Value Measurements, Non-recurring Basis | Level 2
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	0	0	0
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	$ 0	$ 3,042	$ 156,689

Significant Customers - Additio

Significant Customers - Additional Information (Details) - Lease Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Total revenue represented by one company			10.00%
XTO Energy Inc.
Concentration Risk [Line Items]
Total revenue represented by one company	21.00%
Exxon Mobil
Concentration Risk [Line Items]
Total revenue represented by one company		11.00%

Credit Facility - Additional In

Credit Facility - Additional Information (Details)

Apr. 25, 2017USD ($)

Oct. 31, 2016USD ($)

Oct. 30, 2016

Dec. 31, 2017USD ($)

Sep. 30, 2017USD ($)

Jun. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Sep. 30, 2016USD ($)

Jun. 30, 2016USD ($)

Apr. 15, 2016USD ($)

Mar. 31, 2016USD ($)

Line Of Credit Facility [Line Items]

Credit facility

$ 388,000,000

$ 362,000,000

$ 393,000,000

$ 388,000,000

$ 316,000,000

$ 299,000,000

$ 285,000,000

$ 116,000,000

Senior Line of Credit

Line Of Credit Facility [Line Items]

Maximum borrowing capacity

$ 1,000,000,000

Weighted average interest rate (percent)

4.06%

3.26%

Current ratio

1

Credit facility

$ 388,000,000

$ 316,000,000

Unused portion of current borrowing base

$ 162,000,000

$ 184,000,000

Senior Line of Credit | Federal funds effective rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

0.50%

Senior Line of Credit | Borrowing Base Utilization Percentage Less Than 50%

Line Of Credit Facility [Line Items]

Commitment fee payable rate (percent)

0.375%

Senior Line of Credit | Borrowing Base Utilization Percentage Equal to or Greater Than 50%

Line Of Credit Facility [Line Items]

Commitment fee payable rate (percent)

0.50%

Senior Line of Credit | Minimum

Line Of Credit Facility [Line Items]

Current ratio

1

Senior Line of Credit | Minimum | LIBOR Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.50%

Senior Line of Credit | Minimum | Prime Rate Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

0.50%

Senior Line of Credit | Maximum

Line Of Credit Facility [Line Items]

Ratio of total debt to EBITDAX

3.5

Senior Line of Credit | Maximum | LIBOR Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

2.50%

Senior Line of Credit | Maximum | Prime Rate Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.50%

Senior Line of Credit | Revolving Credit Facility

Line Of Credit Facility [Line Items]

Borrowing base

$ 550,000,000

$ 500,000,000

$ 450,000,000

Debt instrument, term

5 years

Borrowing base threshold (percent)

50.00%

Senior Line of Credit | Revolving Credit Facility | Minimum | LIBOR Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

2.00%

Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.00%

Senior Line of Credit | Revolving Credit Facility | Maximum | LIBOR Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

3.00%

Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate

Line Of Credit Facility [Line Items]

Interest rate (percent)

2.00%

Incentive Compensation - Additi

Incentive Compensation - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash Bonus, requisite service period		4 years
Cash reclassified to equity settled liabilities	$ 10,100,000
Granted, weighted average grant date fair value (in usd per share)		$ 18.48	$ 10.09	$ 18.79
Fair value of units vested		$ 11,900,000	$ 9,400,000	$ 25,100,000
Cash payments of vested units		$ 0	$ 0	$ 0
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units		901,910
Granted, weighted average grant date fair value (in usd per share)		$ 18.48
Unrecognized compensation cost		$ 15.7
Period of weighted average recognition		1 year 7 months 24 days
Subordinated Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units		0
Granted, weighted average grant date fair value (in usd per share)		$ 0
Unrecognized compensation cost		$ 0.2
Period of weighted average recognition		2 months 12 days
Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units		438,288
Granted, weighted average grant date fair value (in usd per share)		$ 17.99
Unrecognized compensation cost		$ 10,100,000
Period of weighted average recognition		1 year 6 months 15 days

Incentive Compensation - Summar

Incentive Compensation - Summary of Information about Restricted Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted, weighted average grant date fair value (in usd per share)	$ 18.48	$ 10.09	$ 18.79
Common Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested, beginning of period (in shares)	1,271,215
Granted (in shares)	901,910
Vested (in shares)	(602,764)
Converted (in shares)	0
Forfeited (in shares)	(28,303)
Unvested, end of period (in shares)	1,542,058	1,271,215
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning of period, weighted average grant date fair value (in usd per share)	$ 15.29
Granted, weighted average grant date fair value (in usd per share)	18.48
Vested, weighted average grant date fair value (in usd per share)	15.13
Converted, weighted average grant date fair value (in usd per share)	0
Forfeited, weighted average grant date fair value (in usd per share)	17.64
Unvested, end of period, weighted average grant date fair value (in usd per share)	$ 16.72	$ 15.29
Subordinated Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested, beginning of period (in shares)	163,041
Granted (in shares)	0
Vested (in shares)	(103,912)
Converted (in shares)	0
Forfeited (in shares)	0
Unvested, end of period (in shares)	59,129	163,041
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning of period, weighted average grant date fair value (in usd per share)	$ 18.97
Granted, weighted average grant date fair value (in usd per share)	0
Vested, weighted average grant date fair value (in usd per share)	19.35
Converted, weighted average grant date fair value (in usd per share)	0
Forfeited, weighted average grant date fair value (in usd per share)	0
Unvested, end of period, weighted average grant date fair value (in usd per share)	$ 18.30	$ 18.97

Incentive Compensation - Summ53

Incentive Compensation - Summarize Information about Performance Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted, weighted average grant date fair value (in usd per share)	$ 18.48	$ 10.09	$ 18.79
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested, beginning of period (in shares)	1,156,419
Granted (in shares)	438,288
Vested (in shares)	0
Forfeited (in shares)	(137,351)
Unvested, end of period (in shares)	1,457,356	1,156,419
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning of period, weighted average grant date fair value (in usd per share)	$ 14.94
Granted, weighted average grant date fair value (in usd per share)	17.99
Vested, weighted average grant date fair value (in usd per share)	0
Forfeited, weighted average grant date fair value (in usd per share)	18.60
Unvested, end of period, weighted average grant date fair value (in usd per share)	$ 15.51	$ 14.94

Incentive Compensation - Summ54

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - 2015 LTIP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 1,412	$ 2,725	$ 15,064
Total incentive compensation expense	34,457	36,663	33,064
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	13,476	13,408	10,137
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	17,367	18,518	4,743
Board of Directors | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 2,202	$ 2,012	$ 3,120

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Details) - 401(k) Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plan Disclosure [Line Items]
Maximum tax-deferred contributions	100.00%
Vesting period	3 years
Partnership's defined contributions	$ 0.6	$ 0.5	$ 0.6
Maximum
Defined Contribution Plan Disclosure [Line Items]
Matching employee contributions	5.00%
After One Year
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	33.00%
After Two Years
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	66.00%
After Three Years
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	100.00%
Service period	3 years

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Rent expense	$ 2,500,000	$ 1,900,000	$ 1,800,000
Provision for remediation costs	$ 0
Samedan
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired	100.00%
Comin
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners	47.34%
Temin
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners	44.39%

Commitments and Contingencies57

Commitments and Contingencies - Summary of Future Minimum Lease Commitments Under Non-cancelable Leases (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 1,654
2,019	38
2,020	16
2,021	0
Total	$ 1,708

Preferred Units - Additional In

Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	Nov. 28, 2017USD ($)$ / shares	May 05, 2016	Nov. 06, 2015USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)
Class of Stock [Line Items]
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively				$ 322,422	$ 54,015		$ 27,092	$ 27,085	$ 34,145	$ 54,015	$ 54,001	$ 54,001
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs				$ 293,469	$ 0	$ 0
Preferred Units
Class of Stock [Line Items]
Partners' equity, preferred units, outstanding (in units) | shares				26,363	52,691
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively				$ 27,000	$ 54,000
Accrued distributions				$ 700	$ 1,300
Preferred units distribution rate (percent)				10.00%
Unpaid preferred yield (percent)		100.00%
Preferred yield (percent)				10.00%
Adjusted conversion price (in usd per share) | $ / shares				$ 14.2683
Number of preferred units redeemed | shares				19,704	18,461
Amount of preferred stock redeemed				$ 20,200	$ 19,000
Number of preferred units converted | shares				6,624	6,064
Conversion of preferred units to common units				$ 6,600	$ 6,100	$ 39,200
Conversion of stock, shares converted | shares						39,240
Maximum percentage of preferred units repurchase			100.00%
Purchased and cancelled redeemable preferred units | shares			40,747
Cost of purchased and cancelled redeemable preferred units, per unit | $ / shares			$ 1,019.45
Purchased and cancelled redeemable preferred units, total cost			$ 41,500
Common and Subordinated Units
Class of Stock [Line Items]
Aggregate unpaid preferred yield (percent)		100.00%
Interest fair market value (percent)		10.00%
Common Units
Class of Stock [Line Items]
Convertible preferred units conversion ratio				30.3431
Conversion of preferred units | shares				200,996	184,006	1,190,664
Number of shares issued | shares				2,000,000
Subordinated Units
Class of Stock [Line Items]
Convertible preferred units conversion ratio				39.7427
Conversion of preferred units | shares				263,247	240,986	1,559,502
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively				$ 295,394	$ 0
Accrued distributions				$ 1,900
Preferred units distribution rate (percent)				7.00%
Shares, price per share (in dollars per share) | $ / shares	$ 20.3926
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs	$ 300,000
Minimum underlying value for conversion trigger				$ 10,000

Earnings Per Unit - Additional

Earnings Per Unit - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017shares
Common Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	800,000
Subordinated Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	1,100,000
Series B Cumulative Convertible Preferred Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	1,600,000
Restricted Performance Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	0

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share Basic [Line Items]
NET INCOME (LOSS)	$ 19,362	$ 22,034	$ 54,174	$ 61,583	$ (7,286)	$ 37,535	$ (20,810)	$ 10,749	$ 157,153	$ 20,188	$ (101,305)
Net income attributable to noncontrolling interests subsequent to initial public offering									34	12	1,260
Distributions on Series A redeemable preferred units subsequent to initial public offering									(3,117)	(5,763)	(7,522)
Distributable Preferred Stock Dividends									1,925	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	16,779	21,388	53,518	60,460	(8,614)	36,219	(22,111)	8,943	152,145	14,437	(108,017)
Allocation of net loss subsequent to initial public offering attributable to:
General partner interest									0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	$ 16,779	$ 21,388	$ 53,518	$ 60,460	$ (8,614)	$ 36,219	$ (22,111)	$ 8,943	152,145	14,437	(108,017)
Common Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ 98,389	$ 24,669	$ (54,326)
Net loss attributable to common and subordinated units per unit:
Per unit (basic) (in usd per share)	$ 0.15	$ 0.16	$ 0.33	$ 0.37	$ 0.01	$ 0.24	$ (0.08)	$ 0.09	$ 1.01	$ 0.26	$ (0.56)
Weighted average units outstanding, basic (in shares)									97,400	96,073	96,182
Per unit (diluted) (in usd per share)	0.15	0.16	0.33	0.37	0.01	0.24	(0.08)	0.09	$ 1.01	$ 0.26	$ (0.56)
Weighted average units outstanding, diluted (in shares)									97,400	96,243	96,182
Subordinated Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ 53,756	$ (10,232)	$ (53,691)
Net loss attributable to common and subordinated units per unit:
Per unit (basic) (in usd per share)	0.03	0.05	0.22	0.26	(0.11)	0.14	(0.15)	0.01	$ 0.56	$ (0.11)	$ (0.56)
Weighted average units outstanding, basic (in shares)									95,149	95,138	95,057
Per unit (diluted) (in usd per share)	$ 0.03	$ 0.05	$ 0.22	$ 0.26	$ (0.11)	$ 0.14	$ (0.15)	$ 0.01	$ 0.56	$ (0.11)	$ (0.56)
Weighted average units outstanding, diluted (in shares)									95,149	95,138	95,057
Predecessor
Earnings Per Share Basic [Line Items]
NET INCOME (LOSS)									$ 0	$ 0	$ (450)

Common and Subordinated Units (

Common and Subordinated Units (Details) - USD ($) shares in Millions, $ in Millions	6 Months Ended	12 Months Ended
	Sep. 15, 2016	Dec. 31, 2017	Mar. 04, 2016
Class of Stock [Line Items]
Authorized repurchase amount			$ 50
Common units repurchased, units	1.3
Aggregate cost of units repurchased	$ 20.2
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)		15.00%
Preferred units distribution rate (percent)		7.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Subsequent Event bbl in Thousands	Feb. 09, 2018$ / shares	Feb. 27, 2018$ / bblbbl
Common Units
Subsequent Event [Line Items]
Cash distribution declared (in usd per share) | $ / shares	$ 0.3125
Subordinate Units
Subsequent Event [Line Items]
Cash distribution declared (in usd per share) | $ / shares	$ 0.20875
February 2018 Through December 2018 | Swap Contracts | Not Designated as Hedging Instrument | Swap | Oil
Subsequent Event [Line Items]
Derivative Contract, Volume | bbl		35
Derivative Contract, Weighted Average Price | $ / bbl		61.85
FY 2019 | Swap Contracts | Not Designated as Hedging Instrument | Swap | Oil
Subsequent Event [Line Items]
Derivative Contract, Volume | bbl		60
Derivative Contract, Weighted Average Price | $ / bbl		57.58

Supplemental Oil and Natural 63

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition Costs of Properties:
Proved	$ 96,596	$ 40,242	$ 2,302
Unproved	383,535	100,888	60,994
Exploration Costs	618	645	2,592
Development Costs	81,056	73,316	60,056
Total	$ 561,805	$ 215,091	$ 125,944

Supplemental Oil and Natural 64

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Oil and Natural Gas Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 2,258,893	$ 2,091,337
Unproved properties	988,720	605,736
Total	3,247,613	2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,766,842)	(1,652,930)
Oil and natural gas properties, net	$ 1,480,771	$ 1,044,143

Supplemental Oil and Natural 65

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, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period	63,425	49,788	51,109
Revisions of previous estimates	2,277	7,844	(3,037)
Purchases of minerals in place	7,309	2,269	69
Extensions, discoveries and other additions	8,449	15,120	12,110
Production	(13,515)	(11,596)	(10,463)
Balance at the end of the period	67,945	63,425	49,788
Net Proved Developed Reserves	56,727	55,327	44,590
Net Proved Undeveloped Reserves	11,218	8,098	5,198
Noncontrolling Interest
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Net Proved Developed Reserves	61	74	84
Net Proved Undeveloped Reserves	0	0	0
Crude Oil
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period | MBbls	18,368	15,842	17,067
Revisions of previous estimates | MBbls	(1,234)	3,007	(197)
Purchases of minerals in place | MBbls	2,267	1,322	8
Extensions, discoveries and other additions | MBbls	2,050	1,877	2,529
Production | MBbls	(3,552)	(3,680)	(3,565)
Balance at the End of the period | MBbls	17,899	18,368	15,842
Net proved developed reserves | MBbls	17,891	18,150	15,497
Net proved undeveloped reserves | MBbls	8	218	345
Natural Gas Reserves
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period | MMcf	270,339	203,675	204,256
Revisions of previous estimates | MMcf	21,067	29,024	(17,043)
Purchases of minerals in place | MMcf	30,250	5,683	367
Extensions, discoveries and other additions | MMcf	38,397	79,455	57,484
Production | MMcf	(59,779)	(47,498)	(41,389)
Balance at the End of the period | MMcf	300,274	270,339	203,675
Net proved developed reserves | MMcf	233,017	223,057	174,555
Net proved undeveloped reserves | MMcf	67,257	47,282	29,120

Supplemental Oil and Natural 66

Supplemental Oil and Natural Gas Disclosure (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Future cash inflows	$ 1,643,582	$ 1,267,179	$ 1,211,290
Future production costs	(211,064)	(193,749)	(205,861)
Future development costs	(70,111)	(36,509)	(84,746)
Future income tax expense	(2,655)	(3,516)	0
Future net cash flows (undiscounted)	1,359,752	1,033,405	920,683
Annual discount 10% for estimated timing	(497,103)	(430,390)	(365,711)
Standardized measure of discounted future net cash flows	$ 862,649	$ 603,015	$ 554,972	$ 1,143,094
Discount for estimated timing of cash flows	10.00%	10.00%	10.00%
Noncontrolling Interest
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 500	$ 600	$ 700

Supplemental Oil and Natural 67

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Standardized measure, beginning of year	$ 603,015	$ 554,972	$ 1,143,094
Sales, net of production costs	(295,941)	(210,354)	(222,206)
Net changes in prices and production costs related to future production	169,608	(81,456)	(621,065)
Extensions, discoveries and improved recovery, net of future production and development costs	113,199	86,606	165,020
Previously estimated development costs incurred during the period	11,118	28,909	7,084
Revisions of estimated future development costs	2,653	0	669
Revisions of previous quantity estimates, net of related costs	86,228	147,507	(67,911)
Accretion of discount	60,512	55,662	114,309
Purchases of reserves in place, less related costs	107,891	34,751	584
Other	4,366	(13,582)	35,394
Net increase (decrease) in standardized measures	259,634	48,043	(588,122)
Standardized measure, end of year	$ 862,649	$ 603,015	$ 554,972

Selected Quarterly Financial 68

Selected Quarterly Financial Information—Unaudited (Details) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)MBoe$ / shares	Sep. 30, 2017USD ($)$ / shares	Jun. 30, 2017USD ($)$ / shares	Mar. 31, 2017USD ($)$ / shares	Dec. 31, 2016USD ($)$ / shares	Sep. 30, 2016USD ($)$ / shares	Jun. 30, 2016USD ($)$ / shares	Mar. 31, 2016USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares	Dec. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)$ / shares
Interim Reporting [Line Items]
Total revenue	$ 95,442	$ 89,111	$ 120,524	$ 124,582	$ 56,712	$ 99,171	$ 40,569	$ 64,381	$ 429,659	$ 260,833	$ 392,924
Income (loss) from operations	23,013	26,216	57,840	65,015	(3,979)	39,316	(19,478)	11,610	172,084	27,469	(95,855)
Net income (loss)	19,362	22,034	54,174	61,583	(7,286)	37,535	(20,810)	10,749	157,153	20,188	(101,305)
Net income (loss) attributable to the general partner and common and subordinated units	16,779	21,388	53,518	60,460	(8,614)	36,219	(22,111)	8,943	152,145	14,437	$ (108,017)
Cash distributions declared and paid per limited partner unit
Total assets	1,576,451	1,246,070	1,250,086	1,199,722	1,128,827	1,137,232	1,126,830	1,045,843	1,576,451	1,128,827
Long-term debt	388,000	362,000	393,000	388,000	316,000	299,000	285,000	116,000	388,000	316,000
Total mezzanine equity	$ 322,422	$ 27,092	$ 27,085	$ 34,145	$ 54,015	$ 54,015	$ 54,001	$ 54,001	$ 322,422	$ 54,015
Reduction in production volume due to cap (in Mboe) | MBoe	1
Common Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic) (in usd per share) | $ / shares	$ 0.15	$ 0.16	$ 0.33	$ 0.37	$ 0.01	$ 0.24	$ (0.08)	$ 0.09	$ 1.01	$ 0.26	$ (0.56)
Per unit (diluted) (in usd per share) | $ / shares	0.15	0.16	0.33	0.37	0.01	0.24	(0.08)	0.09	1.01	0.26	(0.56)
Cash distributions declared and paid per limited partner unit
Per unit (in usd per share) | $ / shares	0.3125	0.3125	0.2875	0.2875	0.2875	0.2875	0.2625	0.2625	1.20	1.10	0.42
Subordinated Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic) (in usd per share) | $ / shares	0.03	0.05	0.22	0.26	(0.11)	0.14	(0.15)	0.01	0.56	(0.11)	(0.56)
Per unit (diluted) (in usd per share) | $ / shares	0.03	0.05	0.22	0.26	(0.11)	0.14	(0.15)	0.01	0.56	(0.11)	(0.56)
Cash distributions declared and paid per limited partner unit
Per unit (in usd per share) | $ / shares	$ 0.2088	$ 0.2088	$ 0.1838	$ 0.1838	$ 0.1838	$ 0.1838	$ 0.1838	$ 0.1838	$ 0.79	$ 0.74	$ 0.42

At-The-Market Offering Progra69

At-The-Market Offering Program (Details) - Common Units shares in Millions	12 Months Ended
	Dec. 31, 2017USD ($)shares
Class of Stock [Line Items]
Equity distribution agreement, maximum	$ 100,000,000
Number of shares issued | shares	2
Proceeds from the sale of common units	$ 32,500,000