Black Stone Minerals (BSM) 10-K 25 Feb 20 2019 FY Annual report Financial data

Cover page

Cover page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 19, 2020	Jun. 28, 2019
Document Information [Line Items]
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Document Annual Report	true
Document Transition Report	false
Entity File Number	001-37362
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-1846692
Entity Address, Address Line One	1001 Fannin Street, Suite 2020
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	445-3200
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	BSM
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2,409,774,181
Documents Incorporated by Reference	Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders.
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Common Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		205,944,172
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, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 8,119	$ 5,414
Accounts receivable	78,214	113,148
Commodity derivative assets	14,790	37,970
Prepaid expenses and other current assets	1,168	1,001
TOTAL CURRENT ASSETS	102,291	157,533
Property, Plant and Equipment [Abstract]
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,073,447 and $1,063,883 at December 31, 2019 and 2018, respectively	3,302,340	3,441,188
Accumulated depreciation, depletion, amortization, and impairment	(1,870,412)	(1,865,692)
Oil and natural gas properties, net	1,431,928	1,575,496
Other property and equipment, net of accumulated depreciation of $11,622 and $11,048 at December 31, 2019 and 2018, respectively	2,300	385
NET PROPERTY AND EQUIPMENT	1,434,228	1,575,881
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	8,689	16,710
TOTAL ASSETS	1,545,208	1,750,124
CURRENT LIABILITIES
Accounts payable	5,309	4,149
Accrued liabilities	22,702	60,089
Commodity derivative liabilities	159	0
Other current liabilities	1,633	528
TOTAL CURRENT LIABILITIES	29,803	64,766
LONG-TERM LIABILITIES
Credit facility	394,000	410,000
Accrued incentive compensation	2,110	1,813
Commodity derivative liabilities	18	0
Asset retirement obligations	15,653	14,948
Other long-term liabilities	6,820	55,973
TOTAL LIABILITIES	448,404	547,500
COMMITMENTS AND CONTINGENCIES (Note 11)
MEZZANINE EQUITY
Temporary equity attributable to parent	298,361	298,361
EQUITY
Partners' equity — general partner interest	0	0
TOTAL EQUITY	798,443	904,263
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,545,208	1,750,124
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Temporary equity attributable to parent	298,361	298,361
Common Units
EQUITY
Partners' equity - units	798,443	714,823
Subordinated Units
EQUITY
Partners' equity - units	$ 0	$ 189,440

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUE
Revenue from contracts with customers	$ 492,776	$ 594,737	$ 402,757
Gain (loss) on commodity derivative instruments	(4,955)	14,831	26,902
TOTAL REVENUE	487,821	609,568	429,659
OPERATING (INCOME) EXPENSE
Lease operating expense	17,665	18,415	17,280
Production costs and ad valorem taxes	60,533	64,364	47,474
Exploration expense	397	7,943	618
Depreciation, depletion, and amortization	109,584	122,653	114,534
General and administrative	63,353	76,712	77,574
Accretion of asset retirement obligations	1,117	1,103	1,026
(Gain) loss on sale of assets, net	0	(3)	(931)
TOTAL OPERATING EXPENSE	252,649	291,187	257,575
INCOME (LOSS) FROM OPERATIONS	235,172	318,381	172,084
OTHER INCOME (EXPENSE)
Interest and investment income	159	183	49
Interest expense	(21,435)	(20,756)	(15,694)
Other income (expense)	472	(2,248)	714
TOTAL OTHER EXPENSE	(20,804)	(22,821)	(14,931)
NET INCOME (LOSS)	214,368	295,560	157,153
Net (income) loss attributable to noncontrolling interests	0	(24)	34
Distributions on Series A redeemable preferred units	0	(25)	(3,117)
Distributions on Series B cumulative convertible preferred units	(21,000)	(21,000)	(1,925)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	193,368	274,511	152,145
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	193,368	274,511	152,145
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of loss	$ 169,375	$ 154,662	$ 98,389
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in usd per share)	$ 1.01	$ 1.46	$ 1.01
Weighted average units outstanding, basic (in shares)	168,230,000	106,064,000	97,400,000
Per unit (diluted) (in usd per share)	$ 1.01	$ 1.45	$ 1.01
Weighted average units outstanding, diluted (in shares)	168,376,000	121,264,000	97,400,000
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of loss	$ 23,993	$ 119,849	$ 53,756
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in usd per share)	$ 0.64	$ 1.25	$ 0.56
Weighted average units outstanding, basic (in shares)	37,740,000	96,099,000	95,149,000
Per unit (diluted) (in usd per share)	$ 0.64	$ 1.25	$ 0.56
Weighted average units outstanding, diluted (in shares)	37,740,000	96,346,000	95,149,000
Crude Oil
REVENUE
Revenue from contracts with customers	$ 263,678	$ 310,278	$ 169,728
Natural Gas
REVENUE
Revenue from contracts with customers	199,265	248,243	190,967
Real Estate
REVENUE
Revenue from contracts with customers	$ 29,833	$ 36,216	$ 42,062

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Series A Redeemable Preferred Units	Series B Cumulative Convertible Preferred Units	Noncontrolling Interest	Common Units	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
Balance at the beginning of the period, units at Dec. 31, 2016					95,721,000	95,164,000
Balance at the beginning of the period at Dec. 31, 2016	$ 671,646			$ 1,021			$ 489,023			$ 181,602
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units					201,000	263,000
Conversion of redeemable preferred units	6,624						2,868			3,756
Repurchases of units (in shares)					(446,000)	(39,000)
Repurchases of units	(8,185)						(7,893)			(292)
Issuance of common units for initial public offering, net of offering costs (in shares)					2,002,000
Issuance of common units, net of offering costs	32,458						32,458
Issuance of units for acquisitions (in shares)					4,348,000
Issuance of common units for property acquisitions	$ 71,723						71,723
Restricted units granted, net of forfeitures (in shares)	0				1,630,000
Equity-based compensation	$ 39,357						39,205			152
Distributions	(194,919)			(120)			(119,963)			(74,836)
Charges to partners' equity for accrued distribution equivalent rights	(2,694)						(2,694)
Net income (loss)	157,153			(34)			101,891			55,296
Distributions on redeemable preferred units		$ (3,117)	$ (1,925)					$ (1,577)	$ (1,925)		$ (1,540)	$ 0
Balance at the end of the period, units at Dec. 31, 2017					103,456,000	95,388,000
Balance at the end of the period at Dec. 31, 2017	768,121			867			603,116			164,138
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units					736,000	964,000
Conversion of redeemable preferred units	24,248						10,498			13,750
Repurchases of units (in shares)					(623,000)	(23,000)
Repurchases of units	(11,221)						(10,879)			(342)
Issuance of common units for initial public offering, net of offering costs (in shares)					2,244,000
Issuance of common units, net of offering costs	40,537						40,537
Issuance of units for acquisitions (in shares)					1,234,000
Issuance of common units for property acquisitions	$ 22,657						22,657
Restricted units granted, net of forfeitures (in shares)	0				1,316,000
Equity-based compensation	$ 40,952						40,733			219
Distributions	(250,162)			(211)			(141,777)			(108,174)
Charges to partners' equity for accrued distribution equivalent rights	(3,698)						(3,698)
Net income (loss)	295,560			24			175,675			119,861
Distributions on redeemable preferred units		$ (25)	$ (21,000)					$ (13)	$ (21,000)		$ (12)
Purchase of noncontrolling interests	(1,706)			(680)			(1,026)
Balance at the end of the period, units at Dec. 31, 2018					108,363,000	96,329,000
Balance at the end of the period at Dec. 31, 2018	904,263			0			714,823			189,440
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of redeemable preferred units, units					96,329,000	(96,329,000)
Conversion of redeemable preferred units	0						142,149			(142,149)
Repurchases of units (in shares)					(966,000)
Repurchases of units	(16,287)						(16,287)
Issuance of common units, net of offering costs	(43)						(43)
Issuance of units for acquisitions (in shares)					57,000
Issuance of common units for property acquisitions	$ 943						943
Restricted units granted, net of forfeitures (in shares)	0				2,177,000
Equity-based compensation	$ 23,490						23,490
Distributions	(304,439)						(233,155)			(71,284)
Charges to partners' equity for accrued distribution equivalent rights	(2,852)						(2,852)
Net income (loss)	214,368						190,375			23,993
Distributions on redeemable preferred units	(21,000)						(21,000)
Balance at the end of the period, units at Dec. 31, 2019					205,960,000	0
Balance at the end of the period at Dec. 31, 2019	$ 798,443			$ 0			$ 798,443			$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 214,368	$ 295,560	$ 157,153
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	109,584	122,653	114,534
Accretion of asset retirement obligations	1,117	1,103	1,026
Amortization of deferred charges	1,041	905	877
(Gain) loss on commodity derivative instruments	4,955	(14,831)	(26,902)
Net cash (paid) received on settlement of commodity derivative instruments	27,862	(38,235)	15,211
Equity-based compensation	20,484	30,134	33,044
Exploratory dry hole expense	3	6,785	0
Deferred rent	0	1,283	0
(Gain) loss on sale of assets, net	0	(3)	(931)
Changes in operating assets and liabilities:
Accounts receivable	35,044	(31,531)	(6,084)
Prepaid expenses and other current assets	(167)	210	(177)
Accounts payable, accrued liabilities, and other	(1,191)	11,474	(5,671)
Settlement of asset retirement obligations	(380)	(129)	(228)
NET CASH PROVIDED BY OPERATING ACTIVITIES	412,720	385,378	281,852
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(43,051)	(124,081)	(425,667)
Additions to oil and natural gas properties	(64,782)	(166,970)	(55,842)
Payments To Acquire Oil And Gas Leasehold Costs	(980)	(6,263)	(2,806)
Purchases of other property and equipment	(2,488)	(21)	(207)
Proceeds from the sale of oil and natural gas properties	1,174	9,009	11,102
Proceeds from farmouts of oil and natural gas properties	61,504	124,522	19,171
NET CASH USED IN INVESTING ACTIVITIES	(48,623)	(163,804)	(454,249)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units, net of offering costs	(43)	40,537	32,458
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs	0	0	293,469
Distributions to noncontrolling interests	0	(211)	(120)
Distributions equivalents paid	(2,981)	0	0
Redemption of Series A redeemable preferred units	0	(2,115)	(19,704)
Purchase of noncontrolling interests	0	(1,706)	0
Borrowings under credit facility	334,500	373,500	292,500
Repayments under credit facility	(350,500)	(351,500)	(220,500)
Debt issuance costs and other	0	(1,242)	(3,075)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(361,392)	(221,802)	168,267
NET CHANGE IN CASH AND CASH EQUIVALENTS	2,705	(228)	(4,130)
Cash and cash equivalents — beginning of the year	5,414	5,642	9,772
Cash and cash equivalents — end of the year	8,119	5,414	5,642
SUPPLEMENTAL DISCLOSURE
Interest paid	20,470	19,761	14,761
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(304,439)	(250,121)	(194,799)
Repurchases of equity units	(16,929)	(10,579)	(8,185)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	0	(690)	(3,777)
Series B Cumulative Convertible Preferred Units | Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (21,000)	$ (17,675)	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties, unproved property costs	$ 1,073,447	$ 1,063,883
Other property and equipment accumulated depreciation and amortization	$ 11,622	$ 11,048
Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in units)	14,711	14,711
Common Units
Partners' equity - units, outstanding	205,960	108,363
Subordinated Units
Partners' equity - units, outstanding	0	96,329

Business and Basis of Presentat

Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2019
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 that owns oil and natural gas 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 in the continental United States ("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. On May 6, 2015, the Partnership completed its initial public offering (the "IPO") of 22,500,000 common units representing limited partner interests. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM." 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, 2019, as discussed in Note 4 – Oil and Natural Gas Properties. In the opinion of management, all 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 using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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. The following table presents information about the Partnership's accounts receivable: December 31, 2019 2018 (in thousands) Accounts receivable: Revenues from contracts with customers $ 71,022 $ 107,804 Other 7,192 5,344 Total accounts receivable $ 78,214 $ 113,148 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 generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. The costs of unproved leasehold 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 the Partnership also refers 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 estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to the Partnership’s producing oil and natural gas properties was $109.0 million, $122.5 million, and $114.3 million for the years ended December 31, 2019, 2018, and 2017, 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, operating costs, future capital expenditures, and a risk-adjusted discount rate. There was no impairment of proved oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. 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 years ended December 31, 2019, 2018, and 2017. 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 3 years to 7 years. Depreciation and amortization expense totaled $0.6 million, $0.2 million, and $0.2 million for the years ended December 31, 2019, 2018, and 2017, 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: December 31, 2019 2018 (in thousands) Accrued liabilities: Accrued capital expenditures $ 2,019 $ 32,945 Accrued incentive compensation 9,057 16,109 Accrued property taxes 8,131 5,822 Accrued other 3,495 5,213 Total accrued liabilities $ 22,702 $ 60,089 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 $1.0 million, $0.9 million, and $0.9 million for the years ended December 31, 2019, 2018, and 2017, 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. Leases On January 1, 2019, the Partnership adopted ASC 842, Leases , using the modified retrospective method. ASC 842 requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Partnership used January 1, 2019, the beginning of the period of adoption, as its date of initial application. The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard. The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019. ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of December 31, 2019 and were not considered material to the Partnership. There was no related impact on the consolidated statement of operations. The standard had no impact on the Partnership’s debt covenant compliance under existing agreements. The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets. As of December 31, 2019, none of the Partnership’s leases were classified as financing leases. ROU assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments. The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Partnership will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities. Revenues from Contracts with Customers ASC 606, Revenue from Contracts with Customers , requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018. Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is 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. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership recognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Production imbalances The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. Allocation of transaction price to remaining performance obligations Oil and natural gas sales The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial. 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, 2019 and 2018 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 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 August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the adoption of this update will have an impact on its financial position, results of operations, or liquidity.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (in thousands) Beginning asset retirement obligations $ 15,475 $ 14,509 Liabilities incurred 209 245 Liabilities settled (1,073) (129) Accretion expense 1,117 1,103 Revisions in estimated costs 976 (16) Dispositions (620) (237) Ending asset retirement obligations $ 16,084 $ 15,475 Current asset retirement obligations $ 431 $ 527 Non-current asset retirement obligations $ 15,653 $ 14,948

Oil and Natural Gas Properties

Oil and Natural Gas Properties Acquisitions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Oil and Natural Gas Properties Acquisitions	OIL AND NATURAL GAS PROPERTIES Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. 2019 Acquisitions During the year ended December 31, 2019, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $44.0 million. Acquisitions that were considered business combinations were primarily located in the Permian Basin. These acquisitions were funded with borrowings under the Partnership's Credit Facility (as defined in Note 8 - Credit Facility) and funds from operating activities. Acquisition related costs of $0.1 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2019. The following table summarizes these acquisitions: Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash (in thousands) February $ 173 $ 8,437 $ 1 $ 8,611 $ 8,611 March 24 — — 24 24 June 527 3,268 — 3,795 3,795 Total fair value $ 724 $ 11,705 $ 1 $ 12,430 $ 12,430 In addition, during 2019, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for an aggregate of $31.6 million. These acquisitions were primarily located in East Texas and the Permian Basin. The cash portion of the consideration paid for these acquisitions of $30.7 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $0.9 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. 2018 Acquisitions During the year ended December 31, 2018, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $149.9 million. Acquisitions that were considered business combinations were primarily located in the Permian Basin. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. Acquisition related costs of $0.2 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2018. The following table summarizes these acquisitions: Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued (in thousands) March $ 984 $ 21,452 $ 133 $ 22,569 $ 22,569 $ — June 883 13,688 8 14,579 14,579 — July 4,349 7,944 215 12,508 3,764 8,744 August 5,000 34,673 74 39,747 26,461 13,286 September 1,176 — — 1,176 1,176 — November 1,166 — — 1,166 1,166 — Total fair value $ 13,558 $ 77,757 $ 430 $ 91,745 $ 69,715 $ 22,030 In addition, during 2018, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for an aggregate of $58.2 million. These acquisitions were primarily located in East Texas and the Permian Basin. The cash portion of the consideration paid for these acquisitions of $57.6 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $0.6 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. During 2018, the Partnership acquired the remaining noncontrolling interest in certain subsidiaries for $1.7 million and merged the subsidiaries into its existing structure. This acquisition was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. Noble Acquisition On November 28, 2017 (the "Close Date"), Black Stone Minerals Company, L.P. ("BSMC"), a wholly owned subsidiary of BSM, 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 was completed in 2018 after post-closing purchase price adjustments were finalized. Since December 31, 2017, the Partnership has recorded an adjustment to the purchase price to reduce the amount allocated to unproved properties by $3.2 million, which reduces the Acquisitions of oil and natural gas properties line item of the consolidated statement of cash flows for the year ended December 31, 2018. The following table summarizes the final allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Proved Unproved Net Working Capital Total Fair Value Cash Consideration Paid 1 Acquisition-Related Costs 2 (in thousands) Noble Assets $ 68,877 $ 256,542 $ 5,917 $ 331,336 $ 331,336 $ 247 1 Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the year ended December 31, 2018. 2 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 were also considered business combinations, during the year ended December 31, 2017. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. The following table summarizes these acquisitions: 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 consolidated statement of operations for the year ended December 31, 2017. In addition, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers in East Texas as reflected in the table below. The cash portion of the consideration paid for these acquisitions 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 In 2017, the Partnership entered into two farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests. Canaan Farmout 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. ("XTO Energy"), a subsidiary of Exxon Mobil Corporation. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 20 wells were drilled over an initial phase, beginning with wells spud after January 1, 2017. Canaan elected to participate in an additional phase that began in September 2018 and continues for the earlier of 2 years or until 20 wells have been drilled. As of December 31, 2019, a total of 17 wells have been drilled during the second phase. After the completion of the second phase, Canaan will have the option to elect to participate in a similar third phase. During the first three phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of the Partnership's drilling and completion costs and is assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. 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 receives an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2019, the Partnership has received $90.0 million from Canaan under the agreement as reimbursement for capital costs associated with farmed-out working interests. When such reimbursements are received prior to assigning the wells to Canaan, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities. When working interests in farmout wells are assigned to Canaan, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Canaan. Pivotal Farmout On November 21, 2017, the Partnership entered into a farmout agreement with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC. The farmout agreement 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), until November 2025. Pivotal will earn the Partnership's remaining working interest in wells operated by XTO Energy in San Augustine County, Texas not covered by the Canaan Farmout (10% working interest on an 8/8th basis), 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 BPX Energy in San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. From the inception of the agreement through December 31, 2019, a total of 68 wells have been drilled in the contract area and the Partnership has received $115.2 million from Pivotal under the agreement as reimbursement for capital costs associated with farmed-out working interests. When such reimbursements are received prior to assigning the wells to Pivotal, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities. When working interests in farmout wells are assigned to Pivotal, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Pivotal. The Partnership's development agreement with BPX Energy terminated in 2019 with respect to the majority of the Partnership's acreage covered by the agreement. As such, Pivotal retains minimal rights or obligations related to the farmout for that area. The Partnership remains engaged with Pivotal around farmout opportunities with potential new operators in the area forfeited by BPX Energy. As of December 31, 2018, $11.6 million and $41.2 million were included in the Other long-term liability line item of the consolidated balance sheet related to the farmout agreements with Canaan and Pivotal, respectively.

Commodity Derivative Financial

Commodity Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
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, 2019, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts and costless collar contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling 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, 2019 and 2018. 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 that may adversely impact the fair value of the Partnership's commodity derivative assets. 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, 2019, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Partnership's Credit Facility. 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 as of each date: As of December 31, 2019 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 $ 19,028 $ (4,238) $ 14,790 Long-term asset Deferred charges and other long-term assets 713 (105) 608 Total assets $ 19,741 $ (4,343) $ 15,398 Liabilities: Current liability Commodity derivative liabilities $ 4,397 $ (4,238) $ 159 Long-term liability Commodity derivative liabilities 123 (105) 18 Total liabilities $ 4,520 $ (4,343) $ 177 As of December 31, 2018 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 $ 38,746 $ (776) $ 37,970 Long-term asset Deferred charges and other long-term assets 11,518 (1,450) 10,068 Total assets $ 50,264 $ (2,226) $ 48,038 Liabilities: Current liability Commodity derivative liabilities $ 776 $ (776) $ — Long-term liability Commodity derivative liabilities 1,450 (1,450) — Total liabilities $ 2,226 $ (2,226) $ — 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 consolidated statements of cash flows and consist of the following for the periods presented: For the year ended December 31, Derivatives not designated as hedging instruments 2019 2018 2017 (in thousands) Beginning fair value of commodity derivative instruments $ 48,038 $ (5,028) $ (16,719) Gain (loss) on oil derivative instruments (34,728) 24,300 (5,091) Gain (loss) on natural gas derivative instruments 29,773 (9,469) 31,993 Net cash paid (received) on settlements of oil derivative instruments (8,536) 34,905 (10,901) Net cash paid (received) on settlements of natural gas derivative instruments (19,326) 3,330 (4,310) Net change in fair value of commodity derivative instruments (32,817) 53,066 11,691 Ending fair value of commodity derivative instruments $ 15,221 $ 48,038 $ (5,028) The Partnership had the following open derivative contracts for oil as of December 31, 2019: Volume (Bbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2019 Fourth quarter 312,000 $ 58.50 $ 52.82 $ 63.75 2020 First quarter 630,000 $ 57.32 $ 54.92 $ 58.65 Second quarter 630,000 57.32 54.92 58.65 Third quarter 630,000 57.32 54.92 58.65 Fourth quarter 630,000 57.32 54.92 58.65 Volume (Bbl) Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl) Period and Type of Contract Oil Collar Contracts: 2019 Fourth quarter 20,000 $ 65.00 $ 74.00 2020 First quarter 210,000 $ 56.43 $ 67.14 Second quarter 210,000 56.43 67.14 Third quarter 210,000 56.43 67.14 Fourth quarter 210,000 56.43 67.14 The Partnership had the following open derivative contracts for natural gas as of December 31, 2019: Volume (MMBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2020 First quarter 10,010,000 $ 2.69 $ 2.55 $ 2.74 Second quarter 10,010,000 2.69 2.55 2.74 Third quarter 10,120,000 2.69 2.55 2.74 Fourth quarter 10,120,000 2.69 2.55 2.74

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018. The carrying value of the Partnership's 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, 2019 and 2018 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, 2019 Financial Assets Commodity derivative instruments $ — $ 19,741 $ — $ (4,343) $ 15,398 Financial Liabilities Commodity derivative instruments — 4,520 — (4,343) 177 As of December 31, 2018 Financial Assets Commodity derivative instruments $ — $ 50,264 $ — $ (2,226) $ 48,038 Financial Liabilities Commodity derivative instruments — 2,226 — (2,226) — 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 estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, 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. 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, operating costs, 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, 2019 and 2018. There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended December 31, 2019, 2018, and 2017.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Significant Customers	SIGNIFICANT CUSTOMERSThe Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. XTO Energy represented approximately 18%, 15%, and 21% of total oil and natural gas revenue for the years ended December 31, 2019, 2018, and 2017. 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, 2019
Debt Disclosure [Abstract]
Credit Facility	CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on November 1, 2022. The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Effective May 4, 2018, the borrowing base redetermination increased the borrowing base from $550.0 million to $600.0 million. Effective October 31, 2018, the borrowing base was further increased to $675.0 million and remained at that level until the most recent redetermination, effective October 23, 2019, which reduced the borrowing base to $650.0 million. Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. Prior to October 31, 2018, the applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base. Effective October 31, 2018, the applicable margin for the alternative base rate was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR was reduced to between 1.75% and 2.75%. The weighted-average interest rate of the Credit Facility was 4.05% and 4.76% as of December 31, 2019 and 2018, 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, 2019, the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was $394.0 million and $410.0 million at December 31, 2019 and 2018, respectively. The unused portion of the available borrowings under the Credit Facility were $256.0 million and $265.0 million at December 31, 2019 and 2018, respectively.

Incentive Compensation

Incentive Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Incentive Compensation	INCENTIVE COMPENSATION Overview The board of directors of the Partnership’s general partner (the "Board") 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 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 common 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 Restricted Unit Awards 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, including the right to receive distributions thereon, if and when made by the Partnership. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method. 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 that extended through March 15, 2019. The Compensation Committee of the Board (the "Compensation Committee") annually approves a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees. Consistent with previous awards the 2019 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2022. In January of each year, 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. The following table summarizes information about restricted units for the year ended December 31, 2019. Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2018 1,334,016 $ 17.29 Granted 496,316 17.09 Vested (778,956) 16.64 Converted — — Forfeited (13,117) 17.49 Unvested at December 31, 2019 1,038,259 17.67 The weighted-average grant-date fair value per unit for unit-based awards was $17.09, $17.95, and $18.48 for the years ended December 31, 2019, 2018, and 2017, respectively. As of December 31, 2019, unrecognized compensation cost associated with restricted unit awards was $8.5 million, which the Partnership expects to recognize over a weighted-average period of 1.67 years. The fair value of units vested for the years ended December 31, 2019, 2018, and 2017 was $12.7 million, $12.9 million, and $25.1 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2019, 2018, and 2017. Performance Unit Awards The Compensation Committee also approves 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 following table summarizes information about performance units for the year ended December 31, 2019. Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2018 1,811,810 $ 15.94 Granted 1 953,638 16.84 Vested (1,378,188) 14.83 Forfeited (18,178) 17.63 Unvested at December 31, 2019 1,369,082 17.66 1 Includes 457,322 of additional performance units issued based on the final performance multiplier for awards that vested in the period. The weighted-average grant-date fair value per unit for performance unit awards was $16.84, $17.94, and $17.99 for the years ended December 31, 2019, 2018, and 2017, respectively. Unrecognized compensation cost associated with performance unit awards was $6.3 million as of December 31, 2019, which the Partnership expects to recognize over a weighted-average period of 1.82 years. The fair value of performance units vested for the years ended December 31, 2019, and 2018 was $22.7 million, and $1.5 million, respectively. No performance units vested for the year ended December 31, 2017. Incentive Compensation 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, 2019, 2018, and 2017. Year Ended December 31, Incentive compensation expense 2019 2018 2017 (In thousands) Cash — short and long-term incentive plan $ 5,593 $ 9,301 $ 4,373 Equity-based compensation — restricted common and subordinated units 10,751 13,624 13,476 Equity-based compensation — restricted performance units 7,386 14,188 17,367 Board of Directors incentive plan 2,347 2,322 2,202 Total incentive compensation expense $ 26,077 $ 39,435 $ 37,418

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANSBlack 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 90% 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 three

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements and no provision for potential remediation costs has been recorded. Put Option Related to Noble Acquisition By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, 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 45.33% and 42.63% of the mineral interests held of record by Holdings and Temin, respectively, as of December 31, 2019. 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, 2019, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded. Litigation

Preferred Units

Preferred Units	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Redeemable Preferred Units	PREFERRED UNITS Series A Redeemable Preferred Units As of December 31, 2019 and 2018, there were no Series A redeemable preferred units outstanding. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears. The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had 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. The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. For the year ended December 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017. For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield, and 6,624 Series A redeemable preferred units totaling $6.6 million were converted into the equivalent of 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. 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 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.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2019
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 units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership's general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Partnership assesses the Series A redeemable preferred units and the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU. 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. The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2019 2018 2017 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 214,368 $ 295,560 $ 157,153 Net (income) loss attributable to noncontrolling interests — (24) 34 Distributions on Series A redeemable preferred units — (25) (3,117) Distributions on Series B cumulative convertible preferred units (21,000) (21,000) (1,925) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 193,368 $ 274,511 $ 152,145 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 169,375 154,662 98,389 Subordinated units 23,993 119,849 53,756 $ 193,368 $ 274,511 $ 152,145 Weighted average common units outstanding: Weighted average common units outstanding (basic) 168,230 106,064 97,400 Effect of dilutive securities 146 15,200 — Weighted average common units outstanding (diluted) 168,376 121,264 97,400 Weighted average subordinated units outstanding: Weighted average subordinated units outstanding (basic) 37,740 96,099 95,149 Effect of dilutive securities — 247 — Weighted average subordinated units outstanding (diluted) 37,740 96,346 95,149 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 1.01 $ 1.46 $ 1.01 Per subordinated unit (basic) 0.64 1.25 0.56 Per common unit (diluted) 1 1.01 1.45 1.01 Per subordinated unit (diluted) 2 0.64 1.25 0.56 1 For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $21.0 million. 2 For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $0.3 million. The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive: For the Year Ended December 31, 2019 2018 2017 (in thousands) Potentially dilutive securities (common units): Series A redeemable preferred units on an as-converted basis — 189 996 Series B cumulative convertible preferred units on an as-converted basis 14,968 — 1,612 14,968 189 2,608 Potentially dilutive securities (subordinated units): Series A redeemable preferred units on an as-converted basis — — 1,304

Common and Subordinated Units

Common and Subordinated Units	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [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 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 Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, 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 are and, prior to the end of the subordination period (as defined in the Partnership agreement), the subordinated units were, entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units, respectively, under the partnership agreement. The subordination period under the partnership agreement ended on the first business day after the Partnership earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there were no outstanding arrearages on the common units. This test was met upon the payment of the distribution for the first quarter of 2019. Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and the priority right of the common unitholders ceased to exist. The partnership agreement generally provides that any distributions are paid each quarter 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; and • second , to the holders of common units. The following table provides information about the Partnership's per unit distributions to common and subordinated unitholders: Year Ended December 31, 2019 2018 2017 DISTRIBUTIONS DECLARED AND PAID: Per common unit $ 1.48 $ 1.33 $ 1.20 Per subordinated unit 1 0.74 1.13 0.79 1 For the six months ended December 31, 2019 there were no distributions on subordinated units as all subordinated units converted into common units on May 24, 2019. Common Unit Repurchase Program On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes 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. In 2019, the Partnership repurchased a total of 136,665 common units for an aggregate cost of $2.2 million. As of December 31, 2019, the Partnership has repurchased $4.2 million in common units under the repurchase program since inception. The repurchase program is funded from the Partnership's cash on hand or availability under the Credit Facility. Any repurchased units are canceled. 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 amount 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. 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.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Distribution On February 5, 2020, the Board approved a distribution for the period from October 1, 2019 to December 31, 2019 of $0.30 per common unit. Distributions were paid on February 24, 2020 to unitholders of record at the close of business on February 17, 2020. General and Administrative Expense Reductions The Partnership has taken significant steps to reduce its general and administrative expenses, including broad workforce reductions and lower Board and executive compensation levels. The Partnership expects to incur a one-time cash charge of approximately $5 million in the first quarter of 2020 associated with severance agreements for affected employees.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Disclosures	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Natural Gas Disclosure - Unaudited	Geographic Area of Operation All the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Texas, Louisiana, and North Dakota. 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, 2019 2018 2017 (in thousands) Acquisition Costs of Properties 1 : Proved $ 2,288 $ 13,438 $ 96,596 Unproved 41,643 136,079 383,535 Exploration Costs 3 13,544 618 Development Costs 1 34,617 165,198 81,056 Total $ 78,551 $ 328,259 $ 561,805 1 See Note 4 – Oil and Natural Gas Properties for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements. 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, 2019 2018 (in thousands) Proved properties 1 $ 2,228,893 $ 2,377,305 Unproved properties 1,073,447 1,063,883 Total 3,302,340 3,441,188 Accumulated depreciation, depletion, amortization, and impairment (1,870,412) (1,865,692) Oil and natural gas properties, net $ 1,431,928 $ 1,575,496 1 Proved properties include capitalized costs related to farmout wells not yet assigned. 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, 2016 18,368 270,339 63,425 Revisions of previous estimates 1 (2,298) 14,505 120 Purchases of minerals in place 2 2,335 31,323 7,555 Extensions, discoveries and other additions 3 3,046 43,886 10,360 Production (3,552) (59,779) (13,515) Net proved reserves at December 31, 2017 17,899 300,274 67,945 Revisions of previous estimates 1 (35) (11,027) (1,873) Purchases of minerals in place 4 227 419 297 Extensions, discoveries and other additions 3 4,438 95,976 20,434 Production (4,962) (71,622) (16,899) Net proved reserves at December 31, 2018 17,567 314,020 69,904 Revisions of previous estimates 1 951 19,136 4,140 Purchases of minerals in place 4 46 279 92 Extensions, discoveries and other additions 3 3,263 53,158 12,123 Production (4,777) (77,635) (17,716) Net proved reserves at December 31, 2019 17,050 308,958 68,543 Net Proved Developed Reserves 5 December 31, 2017 17,891 233,017 56,727 December 31, 2018 17,567 278,233 63,939 December 31, 2019 17,050 263,371 60,945 Net Proved Undeveloped Reserves 6 December 31, 2017 8 67,257 11,218 December 31, 2018 — 35,787 5,965 December 31, 2019 — 45,587 7,598 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells. 2 Includes the acquisition of mineral and royalty reserves primarily in East Texas, the Permian Basin, and the Williston Basin. 3 Includes extensions and additions related to drilling activities within multiple basins. 4 Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian Basin. 5 As of December 31, 2018 and 2019, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries. As of December 31, 2017, proved developed reserves of 61 MBoe were attributable to noncontrolling interests. 6 As of December 31, 2018, 2017, and 2016, 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, 2019 2018 2017 (in thousands) Future cash inflows $ 1,619,147 $ 2,038,508 $ 1,643,582 Future production costs (177,550) (222,342) (211,064) Future development costs (54,132) (58,403) (70,111) Future income tax expense (5,244) (6,333) (2,655) Future net cash flows (undiscounted) 1,382,221 1,751,430 1,359,752 Annual discount 10% for estimated timing (534,327) (663,814) (497,103) Total 1 $ 847,894 $ 1,087,616 $ 862,649 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million for December 31, 2017 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, 2019 2018 2017 (in thousands) Standardized measure, beginning of year $ 1,087,616 $ 862,649 $ 603,015 Sales, net of production costs (384,745) (475,742) (295,941) Net changes in prices and production costs related to future production (229,651) 275,091 161,221 Extensions, discoveries and improved recovery, net of future production and development costs 186,424 370,695 166,616 Previously estimated development costs incurred during the period — 14,509 11,118 Revisions of estimated future development costs 1,198 (558) 2,653 Revisions of previous quantity estimates, net of related costs 51,405 (5,401) 60,476 Accretion of discount 109,158 86,441 60,512 Purchases of reserves in place, less related costs 1,730 8,975 113,342 Changes in timing and other 24,759 (49,043) (20,363) Net increase (decrease) in standardized measures (239,722) 224,967 259,634 Standardized measure, end of year $ 847,894 $ 1,087,616 $ 862,649 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, 2019
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 Second Third Fourth (In thousands, except for per unit data) 2019 Total revenue $ 83,806 $ 163,618 $ 137,369 $ 103,028 Income (loss) from operations 14,594 100,666 75,233 44,679 Net income (loss) 9,017 95,087 70,247 40,017 Net income (loss) attributable to the general partner and common and subordinated units 3,767 89,837 64,997 34,767 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) $ 0.02 $ 0.45 $ 0.32 $ 0.17 Per subordinated unit (basic) 0.02 0.39 — — Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) $ 0.02 $ 0.44 $ 0.32 $ 0.17 Per subordinated unit (diluted) 0.02 0.39 — — Cash distributions declared and paid per limited partner unit Per common unit $ 0.3700 $ 0.3700 $ 0.3700 $ 0.3700 Per subordinated unit 0.3700 0.3700 — — Total assets $ 1,711,887 $ 1,724,555 $ 1,595,813 $ 1,545,208 Long-term debt 435,000 436,000 413,000 394,000 Total mezzanine equity 298,361 298,361 298,361 298,361 2018 Total revenue $ 114,494 $ 109,309 $ 139,718 $ 246,047 Income (loss) from operations 47,960 33,524 66,180 170,717 Net income (loss) 41,957 28,690 60,775 164,138 Net income (loss) attributable to the general partner and common and subordinated units 36,655 23,488 55,503 158,865 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) $ 0.23 $ 0.17 $ 0.27 $ 0.78 Per subordinated unit (basic) 0.13 0.06 0.27 0.78 Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) $ 0.23 $ 0.17 $ 0.27 $ 0.72 Per subordinated unit (diluted) 0.13 0.06 0.27 0.78 Cash distributions declared and paid per limited partner unit Per common unit $ 0.3125 $ 0.3125 $ 0.3375 $ 0.3700 Per subordinated unit 0.2088 0.2087 0.3375 0.3700 Total assets $ 1,635,978 $ 1,669,464 $ 1,754,259 $ 1,750,124 Long-term debt 436,000 421,000 402,000 410,000 Total mezzanine equity 300,644 298,361 298,361 298,361 1 See Note 13 – Earnings Per Unit in the consolidated financial statements.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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.
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 generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. The costs of unproved leasehold 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 the Partnership also refers to as a depletable unit.
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 3 years to 7 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.
Leases	Leases On January 1, 2019, the Partnership adopted ASC 842, Leases , using the modified retrospective method. ASC 842 requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Partnership used January 1, 2019, the beginning of the period of adoption, as its date of initial application. The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard. The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019. ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of December 31, 2019 and were not considered material to the Partnership. There was no related impact on the consolidated statement of operations. The standard had no impact on the Partnership’s debt covenant compliance under existing agreements. The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets. As of December 31, 2019, none of the Partnership’s leases were classified as financing leases. ROU assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments. The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Partnership will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.
Revenue recognition	Revenues from Contracts with Customers ASC 606, Revenue from Contracts with Customers , requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018. Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is 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. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership recognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Production imbalances The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. Allocation of transaction price to remaining performance obligations Oil and natural gas sales The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
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,
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 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	Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the adoption of this update will have an impact on its financial position, results of operations, or liquidity.
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 units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of Accounts Receivable	The following table presents information about the Partnership's accounts receivable: December 31, 2019 2018 (in thousands) Accounts receivable: Revenues from contracts with customers $ 71,022 $ 107,804 Other 7,192 5,344 Total accounts receivable $ 78,214 $ 113,148
Schedule of Accrued Liabilities	Accrued liabilities consisted of the following: December 31, 2019 2018 (in thousands) Accrued liabilities: Accrued capital expenditures $ 2,019 $ 32,945 Accrued incentive compensation 9,057 16,109 Accrued property taxes 8,131 5,822 Accrued other 3,495 5,213 Total accrued liabilities $ 22,702 $ 60,089

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (in thousands) Beginning asset retirement obligations $ 15,475 $ 14,509 Liabilities incurred 209 245 Liabilities settled (1,073) (129) Accretion expense 1,117 1,103 Revisions in estimated costs 976 (16) Dispositions (620) (237) Ending asset retirement obligations $ 16,084 $ 15,475 Current asset retirement obligations $ 431 $ 527 Non-current asset retirement obligations $ 15,653 $ 14,948

Oil and Natural Gas Propertie_2

Oil and Natural Gas Properties Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes these acquisitions: Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash (in thousands) February $ 173 $ 8,437 $ 1 $ 8,611 $ 8,611 March 24 — — 24 24 June 527 3,268 — 3,795 3,795 Total fair value $ 724 $ 11,705 $ 1 $ 12,430 $ 12,430 In addition, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers in East Texas as reflected in the table below. The cash portion of the consideration paid for these acquisitions 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
Noble Acquisition
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes the final allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Proved Unproved Net Working Capital Total Fair Value Cash Consideration Paid 1 Acquisition-Related Costs 2 (in thousands) Noble Assets $ 68,877 $ 256,542 $ 5,917 $ 331,336 $ 331,336 $ 247 1 Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the year ended December 31, 2018. 2 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.
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)
2018 Acquisitions
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes these acquisitions: Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued (in thousands) March $ 984 $ 21,452 $ 133 $ 22,569 $ 22,569 $ — June 883 13,688 8 14,579 14,579 — July 4,349 7,944 215 12,508 3,764 8,744 August 5,000 34,673 74 39,747 26,461 13,286 September 1,176 — — 1,176 1,176 — November 1,166 — — 1,166 1,166 — Total fair value $ 13,558 $ 77,757 $ 430 $ 91,745 $ 69,715 $ 22,030
2017 Acquisitions
Business Acquisition [Line Items]
Schedule of Fair Values of the Assets Acquired	The following table summarizes these acquisitions: 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 consolidated statement of operations for the year ended December 31, 2017.

Commodity Derivative Financia_2

Commodity Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
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 as of each date: As of December 31, 2019 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 $ 19,028 $ (4,238) $ 14,790 Long-term asset Deferred charges and other long-term assets 713 (105) 608 Total assets $ 19,741 $ (4,343) $ 15,398 Liabilities: Current liability Commodity derivative liabilities $ 4,397 $ (4,238) $ 159 Long-term liability Commodity derivative liabilities 123 (105) 18 Total liabilities $ 4,520 $ (4,343) $ 177 As of December 31, 2018 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 $ 38,746 $ (776) $ 37,970 Long-term asset Deferred charges and other long-term assets 11,518 (1,450) 10,068 Total assets $ 50,264 $ (2,226) $ 48,038 Liabilities: Current liability Commodity derivative liabilities $ 776 $ (776) $ — Long-term liability Commodity derivative liabilities 1,450 (1,450) — Total liabilities $ 2,226 $ (2,226) $ —
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 consolidated statements of cash flows and consist of the following for the periods presented: For the year ended December 31, Derivatives not designated as hedging instruments 2019 2018 2017 (in thousands) Beginning fair value of commodity derivative instruments $ 48,038 $ (5,028) $ (16,719) Gain (loss) on oil derivative instruments (34,728) 24,300 (5,091) Gain (loss) on natural gas derivative instruments 29,773 (9,469) 31,993 Net cash paid (received) on settlements of oil derivative instruments (8,536) 34,905 (10,901) Net cash paid (received) on settlements of natural gas derivative instruments (19,326) 3,330 (4,310) Net change in fair value of commodity derivative instruments (32,817) 53,066 11,691 Ending fair value of commodity derivative instruments $ 15,221 $ 48,038 $ (5,028)
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of December 31, 2019: Volume (Bbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2019 Fourth quarter 312,000 $ 58.50 $ 52.82 $ 63.75 2020 First quarter 630,000 $ 57.32 $ 54.92 $ 58.65 Second quarter 630,000 57.32 54.92 58.65 Third quarter 630,000 57.32 54.92 58.65 Fourth quarter 630,000 57.32 54.92 58.65 Volume (Bbl) Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl) Period and Type of Contract Oil Collar Contracts: 2019 Fourth quarter 20,000 $ 65.00 $ 74.00 2020 First quarter 210,000 $ 56.43 $ 67.14 Second quarter 210,000 56.43 67.14 Third quarter 210,000 56.43 67.14 Fourth quarter 210,000 56.43 67.14 The Partnership had the following open derivative contracts for natural gas as of December 31, 2019: Volume (MMBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2020 First quarter 10,010,000 $ 2.69 $ 2.55 $ 2.74 Second quarter 10,010,000 2.69 2.55 2.74 Third quarter 10,120,000 2.69 2.55 2.74 Fourth quarter 10,120,000 2.69 2.55 2.74

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 Financial Assets Commodity derivative instruments $ — $ 19,741 $ — $ (4,343) $ 15,398 Financial Liabilities Commodity derivative instruments — 4,520 — (4,343) 177 As of December 31, 2018 Financial Assets Commodity derivative instruments $ — $ 50,264 $ — $ (2,226) $ 48,038 Financial Liabilities Commodity derivative instruments — 2,226 — (2,226) —

Incentive Compensation (Tables)

Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of Information about Restricted Units	The following table summarizes information about restricted units for the year ended December 31, 2019. Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2018 1,334,016 $ 17.29 Granted 496,316 17.09 Vested (778,956) 16.64 Converted — — Forfeited (13,117) 17.49 Unvested at December 31, 2019 1,038,259 17.67
Summary of Information about Performance Units	The following table summarizes information about performance units for the year ended December 31, 2019. Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2018 1,811,810 $ 15.94 Granted 1 953,638 16.84 Vested (1,378,188) 14.83 Forfeited (18,178) 17.63 Unvested at December 31, 2019 1,369,082 17.66 1 Includes 457,322 of additional performance units issued based on the final performance multiplier for awards that vested in the period.
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, 2019, 2018, and 2017. Year Ended December 31, Incentive compensation expense 2019 2018 2017 (In thousands) Cash — short and long-term incentive plan $ 5,593 $ 9,301 $ 4,373 Equity-based compensation — restricted common and subordinated units 10,751 13,624 13,476 Equity-based compensation — restricted performance units 7,386 14,188 17,367 Board of Directors incentive plan 2,347 2,322 2,202 Total incentive compensation expense $ 26,077 $ 39,435 $ 37,418

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 214,368 $ 295,560 $ 157,153 Net (income) loss attributable to noncontrolling interests — (24) 34 Distributions on Series A redeemable preferred units — (25) (3,117) Distributions on Series B cumulative convertible preferred units (21,000) (21,000) (1,925) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 193,368 $ 274,511 $ 152,145 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 169,375 154,662 98,389 Subordinated units 23,993 119,849 53,756 $ 193,368 $ 274,511 $ 152,145 Weighted average common units outstanding: Weighted average common units outstanding (basic) 168,230 106,064 97,400 Effect of dilutive securities 146 15,200 — Weighted average common units outstanding (diluted) 168,376 121,264 97,400 Weighted average subordinated units outstanding: Weighted average subordinated units outstanding (basic) 37,740 96,099 95,149 Effect of dilutive securities — 247 — Weighted average subordinated units outstanding (diluted) 37,740 96,346 95,149 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 1.01 $ 1.46 $ 1.01 Per subordinated unit (basic) 0.64 1.25 0.56 Per common unit (diluted) 1 1.01 1.45 1.01 Per subordinated unit (diluted) 2 0.64 1.25 0.56 1 For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $21.0 million. 2 For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $0.3 million. The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive: For the Year Ended December 31, 2019 2018 2017 (in thousands) Potentially dilutive securities (common units): Series A redeemable preferred units on an as-converted basis — 189 996 Series B cumulative convertible preferred units on an as-converted basis 14,968 — 1,612 14,968 189 2,608 Potentially dilutive securities (subordinated units): Series A redeemable preferred units on an as-converted basis — — 1,304

Common and Subordinated Units (

Common and Subordinated Units (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Distributions Made to Limited Partner, by Distribution	The following table provides information about the Partnership's per unit distributions to common and subordinated unitholders: Year Ended December 31, 2019 2018 2017 DISTRIBUTIONS DECLARED AND PAID: Per common unit $ 1.48 $ 1.33 $ 1.20 Per subordinated unit 1 0.74 1.13 0.79

Supplemental Oil and Natural _2

Supplemental Oil and Natural Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in thousands) Acquisition Costs of Properties 1 : Proved $ 2,288 $ 13,438 $ 96,596 Unproved 41,643 136,079 383,535 Exploration Costs 3 13,544 618 Development Costs 1 34,617 165,198 81,056 Total $ 78,551 $ 328,259 $ 561,805 1 See Note 4 – Oil and Natural Gas Properties for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements.
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, 2019 2018 (in thousands) Proved properties 1 $ 2,228,893 $ 2,377,305 Unproved properties 1,073,447 1,063,883 Total 3,302,340 3,441,188 Accumulated depreciation, depletion, amortization, and impairment (1,870,412) (1,865,692) Oil and natural gas properties, net $ 1,431,928 $ 1,575,496 1 Proved properties include capitalized costs related to farmout wells not yet assigned.
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, 2016 18,368 270,339 63,425 Revisions of previous estimates 1 (2,298) 14,505 120 Purchases of minerals in place 2 2,335 31,323 7,555 Extensions, discoveries and other additions 3 3,046 43,886 10,360 Production (3,552) (59,779) (13,515) Net proved reserves at December 31, 2017 17,899 300,274 67,945 Revisions of previous estimates 1 (35) (11,027) (1,873) Purchases of minerals in place 4 227 419 297 Extensions, discoveries and other additions 3 4,438 95,976 20,434 Production (4,962) (71,622) (16,899) Net proved reserves at December 31, 2018 17,567 314,020 69,904 Revisions of previous estimates 1 951 19,136 4,140 Purchases of minerals in place 4 46 279 92 Extensions, discoveries and other additions 3 3,263 53,158 12,123 Production (4,777) (77,635) (17,716) Net proved reserves at December 31, 2019 17,050 308,958 68,543 Net Proved Developed Reserves 5 December 31, 2017 17,891 233,017 56,727 December 31, 2018 17,567 278,233 63,939 December 31, 2019 17,050 263,371 60,945 Net Proved Undeveloped Reserves 6 December 31, 2017 8 67,257 11,218 December 31, 2018 — 35,787 5,965 December 31, 2019 — 45,587 7,598 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells. 2 Includes the acquisition of mineral and royalty reserves primarily in East Texas, the Permian Basin, and the Williston Basin. 3 Includes extensions and additions related to drilling activities within multiple basins. 4 Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian Basin. 5 As of December 31, 2018 and 2019, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries. As of December 31, 2017, proved developed reserves of 61 MBoe were attributable to noncontrolling interests. 6 As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2019 2018 2017 (in thousands) Future cash inflows $ 1,619,147 $ 2,038,508 $ 1,643,582 Future production costs (177,550) (222,342) (211,064) Future development costs (54,132) (58,403) (70,111) Future income tax expense (5,244) (6,333) (2,655) Future net cash flows (undiscounted) 1,382,221 1,751,430 1,359,752 Annual discount 10% for estimated timing (534,327) (663,814) (497,103) Total 1 $ 847,894 $ 1,087,616 $ 862,649 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million for December 31, 2017 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, 2019 2018 2017 (in thousands) Standardized measure, beginning of year $ 1,087,616 $ 862,649 $ 603,015 Sales, net of production costs (384,745) (475,742) (295,941) Net changes in prices and production costs related to future production (229,651) 275,091 161,221 Extensions, discoveries and improved recovery, net of future production and development costs 186,424 370,695 166,616 Previously estimated development costs incurred during the period — 14,509 11,118 Revisions of estimated future development costs 1,198 (558) 2,653 Revisions of previous quantity estimates, net of related costs 51,405 (5,401) 60,476 Accretion of discount 109,158 86,441 60,512 Purchases of reserves in place, less related costs 1,730 8,975 113,342 Changes in timing and other 24,759 (49,043) (20,363) Net increase (decrease) in standardized measures (239,722) 224,967 259,634 Standardized measure, end of year $ 847,894 $ 1,087,616 $ 862,649

Selected Quarterly Financial _2

Selected Quarterly Financial Information—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information	Quarterly financial data was as follows for the periods indicated. First Second Third Fourth (In thousands, except for per unit data) 2019 Total revenue $ 83,806 $ 163,618 $ 137,369 $ 103,028 Income (loss) from operations 14,594 100,666 75,233 44,679 Net income (loss) 9,017 95,087 70,247 40,017 Net income (loss) attributable to the general partner and common and subordinated units 3,767 89,837 64,997 34,767 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) $ 0.02 $ 0.45 $ 0.32 $ 0.17 Per subordinated unit (basic) 0.02 0.39 — — Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) $ 0.02 $ 0.44 $ 0.32 $ 0.17 Per subordinated unit (diluted) 0.02 0.39 — — Cash distributions declared and paid per limited partner unit Per common unit $ 0.3700 $ 0.3700 $ 0.3700 $ 0.3700 Per subordinated unit 0.3700 0.3700 — — Total assets $ 1,711,887 $ 1,724,555 $ 1,595,813 $ 1,545,208 Long-term debt 435,000 436,000 413,000 394,000 Total mezzanine equity 298,361 298,361 298,361 298,361 2018 Total revenue $ 114,494 $ 109,309 $ 139,718 $ 246,047 Income (loss) from operations 47,960 33,524 66,180 170,717 Net income (loss) 41,957 28,690 60,775 164,138 Net income (loss) attributable to the general partner and common and subordinated units 36,655 23,488 55,503 158,865 Net income (loss) attributable to common and subordinated units per unit (basic) 1 Per common unit (basic) $ 0.23 $ 0.17 $ 0.27 $ 0.78 Per subordinated unit (basic) 0.13 0.06 0.27 0.78 Net income (loss) attributable to common and subordinated units per unit (diluted) 1 Per common unit (diluted) $ 0.23 $ 0.17 $ 0.27 $ 0.72 Per subordinated unit (diluted) 0.13 0.06 0.27 0.78 Cash distributions declared and paid per limited partner unit Per common unit $ 0.3125 $ 0.3125 $ 0.3375 $ 0.3700 Per subordinated unit 0.2088 0.2087 0.3375 0.3700 Total assets $ 1,635,978 $ 1,669,464 $ 1,754,259 $ 1,750,124 Long-term debt 436,000 421,000 402,000 410,000 Total mezzanine equity 300,644 298,361 298,361 298,361 1 See Note 13 – Earnings Per Unit in the consolidated financial statements.

Business and Basis of Present_2

Business and Basis of Presentation - Narrative (Details) shares in Thousands	May 06, 2015shares	Dec. 31, 2018shares	Dec. 31, 2017shares	Dec. 31, 2019state
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage				20.00%
Common Units
Limited Partners Capital Account [Line Items]
Issuance of common units for initial public offering, net of offering costs (in shares) | shares	22,500	2,244	2,002
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located | state				41

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Accounts receivable	$ 78,214	$ 113,148
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	78,214	113,148
Customer Contracts
Accounting Policies [Abstract]
Accounts receivable	71,022	107,804
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	71,022	107,804
Other Receivables
Accounting Policies [Abstract]
Accounts receivable	7,192	5,344
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 7,192	$ 5,344

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	$ 109,584	$ 122,653	$ 114,534
Amortization of Debt Issuance Costs	1,000	900	900
Oil and Natural Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	109,000	122,500	114,300
Proved Oil And Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Impairment of oil and natural gas properties	0	0	0
Unproved Oil And Natural Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Impairment of oil and natural gas properties	0	0	0
Other Property and Equipment
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	$ 600	$ 200	$ 200
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 Accoun_6

Summary of Significant Accounting Policies - Total Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Accrued capital expenditures	$ 2,019	$ 32,945
Accrued incentive compensation	9,057	16,109
Accrued property taxes	8,131	5,822
Accrued other	3,495	5,213
Total accrued liabilities	$ 22,702	$ 60,089

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 15,475	$ 14,509
Liabilities incurred	209	245
Liabilities settled	(1,073)	(129)
Accretion expense	1,117	1,103	$ 1,026
Revisions in estimated costs	976	(16)
Dispositions	(620)	(237)
Ending asset retirement obligations	16,084	15,475	$ 14,509
Current asset retirement obligations	431	527
Non-current asset retirement obligations	$ 15,653	$ 14,948

Oil and Natural Gas Propertie_3

Oil and Natural Gas Properties Acquisitions - 2019 Acquisitions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Business combination, consideration transferred	$ 44,000	$ 149,900
Acquisition-related costs	100	200
Issuance of common units, net of offering costs	(43)	40,537	$ 32,458
East Texas
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests	31,600	$ 58,200
2019 Acquisitions
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests	30,700
Issuance of common units, net of offering costs	$ 900

Oil and Natural Gas Propertie_4

Oil and Natural Gas Properties Acquisitions - Schedule of Fair Values of the Assets Acquired (Details) - USD ($) $ in Thousands	Nov. 28, 2017	Jun. 30, 2019	Mar. 31, 2019	Feb. 28, 2019	Nov. 30, 2018	Sep. 30, 2018	Aug. 31, 2018	Jul. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Aug. 31, 2017	Jun. 30, 2017	Jan. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 30, 2017
Business Acquisition [Line Items]
Proved																			$ 2,288	$ 13,438	$ 96,596
Unproved																			41,643	136,079	383,535
Cash		$ 3,795
Acquisition-related costs																			100	200
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
Net Working Capital											0	0	0	263							263
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
Fair Value of Common Units Issued											0	8,972	45,681	12,026							66,679
Acquisition-related costs											0	$ 107	1,481	$ 1,162							2,750
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	256,542
Net Working Capital	5,917
Total Fair Value	331,336
Cash	331,336
Acquisition-related costs	$ 247
Permian Basin
Business Acquisition [Line Items]
Proved		527	$ 24	$ 173															724
Unproved		3,268	0	8,437															11,705
Net Working Capital		0	0	1															1
Total Fair Value		$ 3,795	24	8,611															12,430
Cash			$ 24	$ 8,611															$ 12,430
Permian Basin | 2018 Acquisitions
Business Acquisition [Line Items]
Proved					$ 1,166	$ 1,176	$ 5,000	$ 4,349	$ 883	$ 984										13,558
Unproved					0	0	34,673	7,944	13,688	21,452										77,757
Net Working Capital					0	0	74	215	8	133										430
Total Fair Value					1,166	1,176	39,747	12,508	14,579	22,569										91,745
Cash					1,166	1,176	26,461	3,764	14,579	22,569										69,715
Fair Value of Common Units Issued					$ 0	$ 0	$ 13,286	$ 8,744	$ 0	$ 0										$ 22,030

Oil and Natural Gas Propertie_5

Oil and Natural Gas Properties Acquisitions - 2018 Acquisitions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Business combination, consideration transferred	$ 44,000	$ 149,900
Acquisition-related costs	100	200
Issuance of common units, net of offering costs	(43)	40,537	$ 32,458
Payments to noncontrolling interests	0	1,706	$ 0
East Texas
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests	$ 31,600	58,200
2018 Acquisitions
Business Acquisition [Line Items]
Asset acquisition payments to acquire oil mineral and royalty interests		57,600
Issuance of common units, net of offering costs		600
Payments to noncontrolling interests		$ 1,700

Oil and Natural Gas Propertie_6

Oil and Natural Gas Properties Acquisitions - Noble Acquisitions (Details) $ in Thousands	Nov. 28, 2017USD ($)ashares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Nov. 30, 2018state
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs		$ 0	$ 0	$ 293,469
Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs	$ 300,000
Noble Acquisition
Business Acquisition [Line Items]
Royalty interests spread | state					20
Payments to acquire businesses, gross	335,000
Purchase price adjustment			$ 3,200
Noble Acquisition | Revolving Credit Facility | Senior Line of Credit
Business Acquisition [Line Items]
Maximum borrowing capacity	35,000
Noble Acquisition | Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs	$ 300,000
Number of shares issued (in shares) | shares	14,711,219
Noble Acquisition | Mineral Acres
Business Acquisition [Line Items]
Overriding royalty interests, gross | a	1,100,000
Mineral interests and other non-cost bearing interests acquired, net | a	140,000
Noble Acquisition | Non-participating Royalty Interest
Business Acquisition [Line Items]
Overriding royalty interests, gross | a	380,000
Noble Acquisition | Overriding Royalty Interest
Business Acquisition [Line Items]
Overriding royalty interests, gross | a	600,000

Oil and Natural Gas Propertie_7

Oil and Natural Gas Properties Acquisitions - Actual and Pro Forma Impact of Noble Acquisition (Details) - Noble Acquisition - USD ($) $ in Millions	Nov. 28, 2017	Dec. 31, 2017
Business Acquisition [Line Items]
Revenue of acquiree since acquisition date, actual		$ 2.8
Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Number of shares issued (in shares)	14,711,219

Oil and Natural Gas Propertie_8

Oil and Natural Gas Properties Acquisitions - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Net income (loss) attributable to the general partner and common and subordinated units	$ 154,887	$ 6,513
Noble Acquisition
Business Acquisition [Line Items]
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	0	0
Common Units | Noble Acquisition
ALLOCATION OF NET INCOME (LOSS):
Allocation of loss	$ 99,776	$ 20,696
DISTRIBUTIONS DECLARED AND PAID:
Per unit (basic) (in usd per share)	$ 1.02	$ 0.22
Per unit (diluted) (in usd per share)	$ 1.02	$ 0.22
Subordinated Units | Noble Acquisition
ALLOCATION OF NET INCOME (LOSS):
Allocation of loss	$ 55,111	$ (14,183)
DISTRIBUTIONS DECLARED AND PAID:
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 Propertie_9

Oil and Natural Gas Properties Acquisitions - Canaan Farmout (Details) - Angelina County, Texas - Farmout Agreement $ in Millions	Feb. 21, 2017well	Dec. 31, 2019USD ($)well	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Ownership interest, acreage, percent	50.00%
Exploratory wells, expected to be drilled | well	20	17
Exploratory wells, additional wells to be drilled | well	20
Asset acquisition, number of phases	3
Canaan Resource Partners
Business Acquisition [Line Items]
Asset acquisition, term of phase	2 years
Asset acquisition, ownership interest in wells, percent	80.00%
Asset acquisition, funding requirements, drilling and completion costs, percent	80.00%
Asset acquisition, ownership interest, gross, percent	40.00%
Asset acquisition, third phase, ownership interest in additional wells, gross, percent	20.00%
Asset acquisition, third phase, ownership interest In additional wells, percent	40.00%
Asset acquisition, third phase, funding requirements, drilling and completion costs, percent	40.00%
Revenue of acquiree since acquisition date, actual | $		$ 90
Canaan Resource Partners | Commodity Derivative Liabilities, Long-term
Business Acquisition [Line Items]
Working interests in wells drilled and completed, actual | $		$ 0.9	$ 11.6

Oil and Natural Gas Properti_10

Oil and Natural Gas Properties Acquisitions - Pivotal Farmout (Details) - Farmout Agreement $ in Millions	Nov. 21, 2017well	Feb. 21, 2017well	Dec. 31, 2019USD ($)well	Dec. 31, 2018USD ($)
Angelina County, Texas
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled | well		20	17
Pivotal | San Augustine County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	10.00%
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Exploratory wells, expected to be drilled | well	80
Number of wells | well			68
Revenue of acquiree since acquisition date, actual			$ 115.2
Pivotal | San Augustine County, Texas | Commodity Derivative Liabilities, Long-term
Business Acquisition [Line Items]
Working interests in wells drilled and completed, actual			0.9	$ 41.2
Pivotal | San Augustine County, Texas | Minimum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent	12.50%
Pivotal | San Augustine County, Texas | Maximum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent	25.00%
Canaan Resource Partners | Angelina County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent		40.00%
Revenue of acquiree since acquisition date, actual			90
Canaan Resource Partners | Angelina County, Texas | Commodity Derivative Liabilities, Long-term
Business Acquisition [Line Items]
Working interests in wells drilled and completed, actual			$ 0.9	$ 11.6

Commodity Derivative Financia_3

Commodity Derivative Financial Instruments - Additional Information (Details)	Dec. 31, 2019counterparty
Derivative [Line Items]
Number Of counterparties	9

Commodity Derivative Financia_4

Commodity Derivative Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 19,741	$ 50,264
Effect of counterparty netting, assets	(4,343)	(2,226)
Net carrying value on balance sheet, assets	15,398	48,038
Gross fair value, liabilities	4,520	2,226
Effect of counterparty netting, liabilities	(4,343)	(2,226)
Net carrying value on balance sheet, liabilities	177	0
Commodity Derivative Assets, Current
Derivatives Fair Value [Line Items]
Gross fair value, assets	19,028	38,746
Effect of counterparty netting, assets	(4,238)	(776)
Net carrying value on balance sheet, assets	14,790	37,970
Deferred Charges and Other Long-term Assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	713	11,518
Effect of counterparty netting, assets	(105)	(1,450)
Net carrying value on balance sheet, assets	608	10,068
Commodity Derivative Liabilities, Current
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	4,397	776
Effect of counterparty netting, liabilities	(4,238)	(776)
Net carrying value on balance sheet, liabilities	159	0
Commodity Derivative Liabilities, Long-term
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	123	1,450
Effect of counterparty netting, liabilities	(105)	(1,450)
Net carrying value on balance sheet, liabilities	$ 18	$ 0

Commodity Derivative Financia_5

Commodity Derivative Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	$ (4,955)	$ 14,831	$ 26,902
Net cash (received) paid on settlements of derivative instruments	(27,862)	38,235	(15,211)
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	48,038	(5,028)	(16,719)
Net change in fair value of commodity derivative instruments	(32,817)	53,066	11,691
Ending fair value of commodity derivative instruments	15,221	48,038	(5,028)
Oil | Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	(34,728)	24,300	(5,091)
Net cash (received) paid on settlements of derivative instruments	(8,536)	34,905	(10,901)
Natural Gas | Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	29,773	(9,469)	31,993
Net cash (received) paid on settlements of derivative instruments	$ (19,326)	$ 3,330	$ (4,310)

Commodity Derivative Financia_6

Commodity Derivative Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2019MMBTU$ / bbl$ / MMBTUbbl
Oil | Q4 2019 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | bbl	312
Derivative contract, weighted average price	58.50
Derivative contract, price range low	52.82
Derivative contract, price range high	63.75
Oil | Q4 2019 | Swap Contracts | Other Contract
Derivative [Line Items]
Derivative contract, volume | bbl	20
Derivative contract, price range low	65
Derivative contract, price range high	74
Oil | Q1 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | bbl	630
Derivative contract, weighted average price	57.32
Derivative contract, price range low	54.92
Derivative contract, price range high	58.65
Oil | Q1 2020 | Collar Contract | Other Contract
Derivative [Line Items]
Derivative contract, volume | bbl	210
Derivative contract, price range low	56.43
Derivative contract, price range high	67.14
Oil | Q2 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | bbl	630
Derivative contract, weighted average price	57.32
Derivative contract, price range low	54.92
Derivative contract, price range high	58.65
Oil | Q2 2020 | Collar Contract | Other Contract
Derivative [Line Items]
Derivative contract, volume | bbl	210
Derivative contract, price range low	56.43
Derivative contract, price range high	67.14
Oil | Q3 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | bbl	630
Derivative contract, weighted average price	57.32
Derivative contract, price range low	54.92
Derivative contract, price range high	58.65
Oil | Q3 2020 | Collar Contract | Other Contract
Derivative [Line Items]
Derivative contract, volume | bbl	210
Derivative contract, price range low	56.43
Derivative contract, price range high	67.14
Oil | Q4 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | bbl	630
Derivative contract, weighted average price	57.32
Derivative contract, price range low	54.92
Derivative contract, price range high	58.65
Oil | Q4 2020 | Collar Contract | Other Contract
Derivative [Line Items]
Derivative contract, volume | bbl	210
Derivative contract, price range low	56.43
Derivative contract, price range high	67.14
Natural Gas | Q1 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | MMBTU	10,010
Derivative contract, weighted average price | $ / MMBTU	2.69
Derivative contract, price range low | $ / MMBTU	2.55
Derivative contract, price range high | $ / MMBTU	2.74
Natural Gas | Q2 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | MMBTU	10,010
Derivative contract, weighted average price | $ / MMBTU	2.69
Derivative contract, price range low | $ / MMBTU	2.55
Derivative contract, price range high | $ / MMBTU	2.74
Natural Gas | Q3 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | MMBTU	10,120
Derivative contract, weighted average price | $ / MMBTU	2.69
Derivative contract, price range low | $ / MMBTU	2.55
Derivative contract, price range high | $ / MMBTU	2.74
Natural Gas | Q4 2020 | Swap Contracts | Swap
Derivative [Line Items]
Derivative contract, volume | MMBTU	10,120
Derivative contract, weighted average price | $ / MMBTU	2.69
Derivative contract, price range low | $ / MMBTU	2.55
Derivative contract, price range high | $ / MMBTU	2.74

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, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 19,741	$ 50,264
Effect of counterparty netting, assets	(4,343)	(2,226)
Net carrying value on balance sheet, assets	15,398	48,038
Gross fair value, liabilities	4,520	2,226
Effect of counterparty netting, liabilities	(4,343)	(2,226)
Net carrying value on balance sheet, liabilities	177	0
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	(4,343)	(2,226)
Net carrying value on balance sheet, assets	15,398	48,038
Effect of counterparty netting, liabilities	(4,343)	(2,226)
Net carrying value on balance sheet, liabilities	177	0
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	19,741	50,264
Gross fair value, liabilities	4,520	2,226
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

Significant Customers - Additio

Significant Customers - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lease Revenue | Customer Concentration Risk | XTO Energy Inc.
Concentration Risk [Line Items]
Total revenue represented by one company	18.00%	15.00%	21.00%

Credit Facility - Narrative (De

Credit Facility - Narrative (Details) - USD ($)

Oct. 31, 2018

Oct. 31, 2016

Dec. 31, 2019

Oct. 23, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

May 04, 2018

May 03, 2018

Mar. 31, 2018

Line Of Credit Facility [Line Items]

Credit facility

$ 394,000,000

$ 413,000,000

$ 436,000,000

$ 435,000,000

$ 410,000,000

$ 402,000,000

$ 421,000,000

$ 436,000,000

Senior Line of Credit

Line Of Credit Facility [Line Items]

Maximum borrowing capacity

$ 1,000,000,000

Weighted average interest rate (percent)

4.05%

4.76%

Credit facility

$ 394,000,000

$ 410,000,000

Unused portion of current borrowing base

$ 256,000,000

$ 265,000,000

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 | Maximum

Line Of Credit Facility [Line Items]

Ratio of total debt to EBITDAX

3.5

Senior Line of Credit | Revolving Credit Facility

Line Of Credit Facility [Line Items]

Borrowing base

$ 675,000,000

$ 650,000,000

$ 600,000,000

$ 550,000,000

Borrowing base threshold (percent)

50.00%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.00%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

0.50%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.75%

2.00%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

0.75%

1.00%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

2.75%

3.00%

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

Line Of Credit Facility [Line Items]

Interest rate (percent)

1.75%

2.00%

Incentive Compensation - Additi

Incentive Compensation - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash Bonus, requisite service period	4 years
Cash payments of vested units	$ 0	$ 0	$ 0
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, weighted average grant date fair value (in usd per share)	$ 17.09	$ 17.95	$ 18.48
Unrecognized compensation cost	$ 8.5
Period of weighted average recognition	1 year 8 months 1 day
Fair value of units vested	$ 12,700,000	$ 12,900,000	$ 25,100,000
Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, weighted average grant date fair value (in usd per share)	$ 16.84	$ 17.94	$ 17.99
Unrecognized compensation cost	$ 6,300,000
Period of weighted average recognition	1 year 9 months 25 days
Fair value of units vested	$ 22,700,000	$ 1,500,000

Incentive Compensation - Summar

Incentive Compensation - Summary of Information about Restricted Units (Details) - Common Units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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)	1,334,016
Granted (in shares)	496,316
Vested (in shares)	(778,956)
Converted (in shares)	0
Forfeited (in shares)	(13,117)
Unvested, end of period (in shares)	1,038,259	1,334,016
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)	$ 17.29
Granted, weighted average grant date fair value (in usd per share)	17.09	$ 17.95	$ 18.48
Vested, weighted average grant date fair value (in usd per share)	16.64
Converted (in usd per share)	0
Forfeited, weighted average grant date fair value (in usd per share)	17.49
Unvested, end of period, weighted average grant date fair value (in usd per share)	$ 17.67	$ 17.29

Incentive Compensation - Summ_2

Incentive Compensation - Summarize Information about Performance Units (Details) - Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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)	1,811,810
Granted (in shares)	953,638
Vested (in shares)	(1,378,188)
Forfeited (in shares)	(18,178)
Unvested, end of period (in shares)	1,369,082	1,811,810
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)	$ 15.94
Granted, weighted average grant date fair value (in usd per share)	16.84	$ 17.94	$ 17.99
Vested, weighted average grant date fair value (in usd per share)	14.83
Forfeited, weighted average grant date fair value (in usd per share)	17.63
Unvested, end of period, weighted average grant date fair value (in usd per share)	$ 17.66	$ 15.94
Additional shares authorized (in shares)	457,322

Incentive Compensation - Summ_3

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - 2015 LTIP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash	$ 5,593	$ 9,301	$ 4,373
Incentive compensation expense	26,077	39,435	37,418
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	10,751	13,624	13,476
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	7,386	14,188	17,367
Board of Directors | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive compensation expense	$ 2,347	$ 2,322	$ 2,202

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Details) - 401(k) Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Contribution Plan Disclosure [Line Items]
Maximum tax-deferred contributions	90.00%
Vesting period	3 years
Partnership's defined contributions	$ 0.7	$ 0.7	$ 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)	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
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	45.33%
Temin
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners	42.63%

Preferred Units - Narrative (De

Preferred Units - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 28, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Class of Stock [Line Items]
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs		$ 0	$ 0	$ 293,469
Temporary equity attributable to parent		$ 298,361	$ 298,361		$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 300,644
Preferred Units
Class of Stock [Line Items]
Partners' equity, preferred units, outstanding (in units)		0
Preferred units distribution rate (percent)		10.00%
Adjusted conversion price (in dollars per share)		$ 14.2683
Number of preferred units redeemed (in shares)			2,115	19,704
Amount of preferred stock redeemed			$ 2,100	$ 20,200
Number of preferred units converted (in shares)			24,248	6,624
Conversion of preferred units to common units			$ 24,200	$ 6,600
Common Units
Class of Stock [Line Items]
Convertible preferred units conversion ratio		30.3431
Conversion of preferred units (in units)			735,758	200,996
Number of shares issued (in shares)		0	2,243,775	2,001,823
Subordinated Units
Class of Stock [Line Items]
Convertible preferred units conversion ratio		39.7427
Conversion of preferred units (in units)			963,681	263,247
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units distribution rate (percent)		7.00%
Shares, price per share (in dollars per share)	$ 20.3926
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs	$ 300,000
Minimum underlying value for conversion trigger		$ 10,000
Temporary equity attributable to parent		298,361	$ 298,361
Accrued distributions		$ 5,300	$ 5,300
Series B Cumulative Convertible Preferred Units | Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares)	14,711,219
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs	$ 300,000

Earnings Per Unit - Additional

Earnings Per Unit - Additional Information (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	146,000	15,200,000	0
Subordinated Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	0	247,000	0
Restricted Performance Units | Common Units
Earnings Per Share Basic [Line Items]
Number of performance units award included in calculation of diluted EPU	0
Restricted Performance Units | Subordinated 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, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share Basic [Line Items]
NET INCOME (LOSS)	$ 40,017	$ 70,247	$ 95,087	$ 9,017	$ 164,138	$ 60,775	$ 28,690	$ 41,957	$ 214,368	$ 295,560	$ 157,153
Net (income) loss attributable to noncontrolling interests									0	24	(34)
Distributions on Series A redeemable preferred units									0	(25)	(3,117)
Distributable preferred stock dividends									21,000	21,000	1,925
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	34,767	64,997	89,837	3,767	158,865	55,503	23,488	36,655	193,368	274,511	152,145
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	$ 34,767	$ 64,997	$ 89,837	$ 3,767	158,865	$ 55,503	$ 23,488	$ 36,655	193,368	274,511	152,145
Series B Cumulative Convertible Preferred Units
Net loss attributable to common and subordinated units per unit:
Distributions on preferred units					21,000					21,000
Series A Redeemable Preferred Units
Net loss attributable to common and subordinated units per unit:
Distributions on preferred units					$ 300					300
Common Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ 169,375	$ 154,662	$ 98,389
Net loss attributable to common and subordinated units per unit:
Weighted average units outstanding, basic (in shares)									168,230,000	106,064,000	97,400,000
Number of performance units award included in calculation of diluted EPU									146,000	15,200,000	0
Weighted average units outstanding, diluted (in shares)									168,376,000	121,264,000	97,400,000
Per unit (basic) (in usd per share)	$ 170	$ 320	$ 450	$ 20	$ 0.78	$ 0.27	$ 0.17	$ 0.23	$ 1.01	$ 1.46	$ 1.01
Per unit (diluted) (in usd per share)	170	320	440	20	0.72	0.27	0.17	0.23	$ 1.01	$ 1.45	$ 1.01
Subordinated Units
Allocation of net loss subsequent to initial public offering attributable to:
Allocation of loss									$ 23,993	$ 119,849	$ 53,756
Net loss attributable to common and subordinated units per unit:
Weighted average units outstanding, basic (in shares)									37,740,000	96,099,000	95,149,000
Number of performance units award included in calculation of diluted EPU									0	247,000	0
Weighted average units outstanding, diluted (in shares)									37,740,000	96,346,000	95,149,000
Per unit (basic) (in usd per share)	0	0	390	20	0.78	0.27	0.06	0.13	$ 0.64	$ 1.25	$ 0.56
Per unit (diluted) (in usd per share)	$ 0	$ 0	$ 390	$ 20	$ 0.78	$ 0.27	$ 0.06	$ 0.13	$ 0.64	$ 1.25	$ 0.56

Earnings Per Unit - Schedule of

Earnings Per Unit - Schedule of Potentially Dilutive Securities excluded from Computation of Earnings Per Share (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share Basic [Line Items]
Potentially dilutive securities (in shares)	14,968,000	189,000	2,608,000
Series A redeemable preferred units on an as-converted basis | Common Units
Earnings Per Share Basic [Line Items]
Potentially dilutive securities (in shares)	0	189,000	996,000
Series A redeemable preferred units on an as-converted basis | Subordinate Units
Earnings Per Share Basic [Line Items]
Potentially dilutive securities (in shares)	0	0	1,304,000
Series B cumulative convertible preferred units on an as-converted basis | Subordinate Units
Earnings Per Share Basic [Line Items]
Potentially dilutive securities (in shares)	14,968,000	0	1,612,000

Common and Subordinated Units_2

Common and Subordinated Units (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2019	Nov. 05, 2018
Class of Stock [Line Items]
Partners' capital account, distribution amount per share (in dollars per share)	$ 1.35	$ 1.35
Authorized repurchase amount			$ 75,000,000
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)	15.00%	15.00%
Preferred units distribution rate (percent)		7.00%
Common Units
Class of Stock [Line Items]
Common units repurchased, units		136,665
Aggregate cost of units repurchased		$ 2,200,000
Common units repurchased, units		136,665
Aggregate cost of units repurchased		$ 2,200,000
Common Units | BSMNovember Two Thousand Twenty Eighteen Repurchase Program
Class of Stock [Line Items]
Aggregate cost of units repurchased	$ 4,200,000
Aggregate cost of units repurchased	$ 4,200,000

Common and Subordinated Units -

Common and Subordinated Units - Per share distributions to common and subordinated unitholders (Details) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Units
Class of Stock [Line Items]
Per unit (in usd per share)	$ 0.3700	$ 0.3700	$ 0.3700	$ 0.3700	$ 0.3700	$ 0.3375	$ 0.3125	$ 0.3125	$ 1.48	$ 1.33	$ 1.20
Subordinated Units
Class of Stock [Line Items]
Per unit (in usd per share)	$ 0	$ 0	$ 0.3700	$ 0.3700	$ 0.3700	$ 0.3375	$ 0.2087	$ 0.2088	$ 0.74	$ 1.13	$ 0.79

Common and Subordinated Units_3

Common and Subordinated Units - At the Market Offering Program (Details) - Common Units - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Equity distribution agreement, maximum	$ 100,000,000
Proceeds from the sale of common units		$ 40,500,000	$ 32,500,000
Number of shares issued (in shares)	0	2,243,775	2,001,823

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions	Feb. 05, 2020	Mar. 31, 2020
Forecast
Subsequent Event [Line Items]
Severance costs		$ 5
Common Units
Subsequent Event [Line Items]
Cash distribution declared (in usd per share)	$ 0.30
Subordinate Units
Subsequent Event [Line Items]
Cash distribution declared (in usd per share)	$ 0.30

Supplemental Oil and Natural _3

Supplemental Oil and Natural Gas Disclosures - Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisition Costs of Properties:
Proved	$ 2,288	$ 13,438	$ 96,596
Unproved	41,643	136,079	383,535
Exploration Costs	3	13,544	618
Development Costs	34,617	165,198	81,056
Total	$ 78,551	$ 328,259	$ 561,805

Supplemental Oil and Natural _4

Supplemental Oil and Natural Gas Disclosures - Oil and Natural Gas Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 2,228,893	$ 2,377,305
Unproved properties	1,073,447	1,063,883
Total	3,302,340	3,441,188
Accumulated depreciation, depletion, amortization, and impairment	(1,870,412)	(1,865,692)
Oil and natural gas properties, net	$ 1,431,928	$ 1,575,496

Supplemental Oil and Natural _5

Supplemental Oil and Natural Gas Disclosures - Estimated Net Quantities of Partnership Proved, Proved Developed and Proved Undeveloped Oil and Natural Gas Reserve (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)MBoeMMcfMBbls	Dec. 31, 2018USD ($)MBoeMMcfMBbls	Dec. 31, 2017USD ($)MBoeMBblsMMcf	Dec. 31, 2016USD ($)MBoe
Reserve Quantities [Line Items]
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | $	$ 847,894	$ 1,087,616	$ 862,649	$ 603,015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period	69,904	67,945	63,425
Revisions of previous estimates	4,140	(1,873)	120
Purchases of minerals in place	92	297	7,555
Extensions, discoveries and other additions	12,123	20,434	10,360
Production	(17,716)	(16,899)	(13,515)
Balance at the end of the period	68,543	69,904	67,945
Net proved developed reserves	60,945	63,939	56,727
Net Proved Undeveloped Reserves	7,598	5,965	11,218
Noncontrolling Interest
Reserve Quantities [Line Items]
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | $			$ 500
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Net proved developed reserves	0	0	61
Net Proved Undeveloped Reserves		0	0	0
Crude Oil
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period | MBbls	17,567	17,899	18,368
Revisions of previous estimates | MBbls	951	(35)	(2,298)
Purchases of minerals in place | MBbls	46	227	2,335
Extensions, discoveries and other additions | MBbls	3,263	4,438	3,046
Production | MBbls	(4,777)	(4,962)	(3,552)
Balance at the End of the period | MBbls	17,050	17,567	17,899
Net proved developed reserves | MBbls	17,050	17,567	17,891
Net proved undeveloped reserves | MBbls	0	0	8
Natural Gas Reserves
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at the beginning of the period | MMcf	314,020	300,274	270,339
Revisions of previous estimates | MMcf	19,136	(11,027)	14,505
Purchases of minerals in place | MMcf	279	419	31,323
Extensions, discoveries and other additions | MMcf	53,158	95,976	43,886
Production | MMcf	(77,635)	(71,622)	(59,779)
Balance at the End of the period | MMcf	308,958	314,020	300,274
Net proved developed reserves | MMcf	263,371	278,233	233,017
Net proved undeveloped reserves | MMcf	45,587	35,787	67,257

Supplemental Oil and Natural _6

Supplemental Oil and Natural Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Future cash inflows	$ 1,619,147	$ 2,038,508	$ 1,643,582
Future production costs	(177,550)	(222,342)	(211,064)
Future development costs	(54,132)	(58,403)	(70,111)
Future income tax expense	(5,244)	(6,333)	(2,655)
Future net cash flows (undiscounted)	1,382,221	1,751,430	1,359,752
Annual discount 10% for estimated timing	(534,327)	(663,814)	(497,103)
Standardized measure of discounted future net cash flows	$ 847,894	$ 1,087,616	862,649	$ 603,015
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

Supplemental Oil and Natural _7

Supplemental Oil and Natural Gas Disclosures - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Standardized measure, beginning of year	$ 1,087,616	$ 862,649	$ 603,015
Sales, net of production costs	(384,745)	(475,742)	(295,941)
Net changes in prices and production costs related to future production	(229,651)	275,091	161,221
Extensions, discoveries and improved recovery, net of future production and development costs	186,424	370,695	166,616
Previously estimated development costs incurred during the period	0	14,509	11,118
Revisions of estimated future development costs	1,198	(558)	2,653
Revisions of previous quantity estimates, net of related costs	51,405	(5,401)	60,476
Accretion of discount	109,158	86,441	60,512
Purchases of reserves in place, less related costs	1,730	8,975	113,342
Other	24,759	(49,043)	(20,363)
Net increase (decrease) in standardized measures	(239,722)	224,967	259,634
Standardized measure, end of year	$ 847,894	$ 1,087,616	$ 862,649

Selected Quarterly Financial _3

Selected Quarterly Financial Information—Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interim Reporting [Line Items]
Total revenue	$ 103,028	$ 137,369	$ 163,618	$ 83,806	$ 246,047	$ 139,718	$ 109,309	$ 114,494	$ 487,821	$ 609,568	$ 429,659
Income (loss) from operations	44,679	75,233	100,666	14,594	170,717	66,180	33,524	47,960	235,172	318,381	172,084
Net income (loss)	40,017	70,247	95,087	9,017	164,138	60,775	28,690	41,957	214,368	295,560	157,153
Net income (loss) attributable to the general partner and common and subordinated units	34,767	64,997	89,837	3,767	158,865	55,503	23,488	36,655	193,368	274,511	$ 152,145
Cash distributions declared and paid per limited partner unit
Total assets	1,545,208	1,595,813	1,724,555	1,711,887	1,750,124	1,754,259	1,669,464	1,635,978	1,545,208	1,750,124
Long-term debt	394,000	413,000	436,000	435,000	410,000	402,000	421,000	436,000	394,000	410,000
Total mezzanine equity	$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 298,361	$ 300,644	$ 298,361	$ 298,361
Common Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic) (in usd per share)	$ 170	$ 320	$ 450	$ 20	$ 0.78	$ 0.27	$ 0.17	$ 0.23	$ 1.01	$ 1.46	$ 1.01
Per unit (diluted) (in usd per share)	170	320	440	20	0.72	0.27	0.17	0.23	1.01	1.45	1.01
Cash distributions declared and paid per limited partner unit
Per unit (in usd per share)	0.3700	0.3700	0.3700	0.3700	0.3700	0.3375	0.3125	0.3125	1.48	1.33	1.20
Subordinated Units
Net income (loss) attributable to common and subordinated units per unit (basic)
Per unit (basic) (in usd per share)	0	0	390	20	0.78	0.27	0.06	0.13	0.64	1.25	0.56
Per unit (diluted) (in usd per share)	0	0	390	20	0.78	0.27	0.06	0.13	0.64	1.25	0.56
Cash distributions declared and paid per limited partner unit
Per unit (in usd per share)	$ 0	$ 0	$ 0.3700	$ 0.3700	$ 0.3700	$ 0.3375	$ 0.2087	$ 0.2088	$ 0.74	$ 1.13	$ 0.79