Black Stone Minerals (BSM) 10-K 20 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
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
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 2,692,990,488
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	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001621434
Common units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		210,313,477
Cumulative Convertible Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Firm ID	42
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS
Cash and cash equivalents	$ 70,282	$ 4,307
Accounts receivable	82,253	135,697
Commodity derivative assets	38,273	31,472
Prepaid expenses and other current assets	2,319	1,905
TOTAL CURRENT ASSETS	193,127	173,381
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $890,338 and $909,344 at December 31, 2023 and 2022, respectively	3,026,394	3,003,907
Accumulated depreciation, depletion, amortization, and impairment	(1,961,899)	(1,916,919)
Oil and natural gas properties, net	1,064,495	1,086,988
Other property and equipment, net of accumulated depreciation of $14,163 and $13,461 at December 31, 2023 and 2022, respectively	1,007	1,259
NET PROPERTY AND EQUIPMENT	1,065,502	1,088,247
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	8,255	9,454
TOTAL ASSETS	1,266,884	1,271,082
CURRENT LIABILITIES
Accounts payable	6,270	6,773
Accrued liabilities	17,003	19,729
Commodity derivative liabilities	1,229	3,243
Other current liabilities	1,334	989
TOTAL CURRENT LIABILITIES	25,836	30,734
LONG-TERM LIABILITIES
Credit facility	0	10,000
Accrued incentive compensation	1,699	1,884
Commodity derivative liabilities	81	16
Asset retirement obligations	19,030	15,030
Other long-term liabilities	2,893	3,606
TOTAL LIABILITIES	49,539	61,270
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY
Partners' equity — general partner interest	0	0
TOTAL EQUITY	918,208	911,451
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,266,884	1,271,082
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2023 and 2022, respectively	299,137	298,361
Common units
EQUITY
Partners' equity — common units, 209,991 and 209,407 units outstanding at December 31, 2023 and 2022, respectively	$ 918,208	$ 911,451

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Oil and natural gas properties, unproved property costs	$ 890,338	$ 909,344
Other property and equipment accumulated depreciation and amortization	$ 14,163	$ 13,461
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common units
Partners' equity - units, outstanding (in shares)	209,991	209,407

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUE
Revenue from contracts with customers	$ 501,099	$ 784,284	$ 505,734
Gain (loss) on commodity derivative instruments	91,117	(120,680)	(146,474)
TOTAL REVENUE	592,216	663,604	359,260
OPERATING (INCOME) EXPENSE
Lease operating expense	11,386	12,380	13,056
Production costs and ad valorem taxes	56,979	66,233	49,809
Exploration expense	2,148	193	1,082
Depreciation, depletion, and amortization	45,683	47,804	61,019
General and administrative	51,455	53,652	48,746
Accretion of asset retirement obligations	1,042	861	1,073
(Gain) loss on sale of assets, net	(73)	(17)	(2,850)
TOTAL OPERATING EXPENSE	168,620	181,106	171,935
INCOME (LOSS) FROM OPERATIONS	423,596	482,498	187,325
OTHER INCOME (EXPENSE)
Interest and investment income	1,867	53	1
Interest expense	(2,754)	(6,286)	(5,638)
Other income (expense)	(160)	215	299
TOTAL OTHER EXPENSE	(1,047)	(6,018)	(5,338)
NET INCOME (LOSS)	422,549	476,480	181,987
Distributions on Series B cumulative convertible preferred units	(21,776)	(21,000)	(21,000)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	400,773	455,480	160,987
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0
Allocation of loss	400,773	455,480	160,987
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 400,773	$ 455,480	$ 160,987
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in usd per share)	$ 1.91	$ 2.18	$ 0.77
Per common unit (diluted) (in usd per share)	$ 1.88	$ 2.12	$ 0.77
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding, basic (in shares)	209,970	209,382	208,181
Weighted average common units outstanding, diluted (in shares)	225,105	224,446	208,290
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 288,296	$ 336,287	$ 235,771
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	200,297	434,945	255,671
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 12,506	$ 13,052	$ 14,292

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Series B Cumulative Convertible Preferred Units	Common units	Partners' equity— common units	Partners' equity— common units Series B Cumulative Convertible Preferred Units
Beginning balance (in shares) at Dec. 31, 2020			206,749
Beginning balance at Dec. 31, 2020	$ 760,606			$ 760,606
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common and subordinated units (in shares)			(223)
Repurchases of common units	(1,957)			(1,957)
Issuance of common units for property acquisitions (in shares)			1,087
Issuance of common units for property acquisitions	10,766			10,766
Restricted units granted, net of forfeitures (in shares)			1,053
Equity-based compensation	12,932			12,932
Distributions	(176,924)			(176,924)
Charges to partners' equity for accrued distribution equivalent rights	(1,142)			(1,142)
Distributions on Series B cumulative convertible preferred units		$ (21,000)			$ (21,000)
Net income (loss)	181,987			181,987
Ending balance (in shares) at Dec. 31, 2021			208,666
Ending balance at Dec. 31, 2021	765,268			765,268
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common and subordinated units (in shares)			(262)
Repurchases of common units	(2,991)			(2,991)
Restricted units granted, net of forfeitures (in shares)			1,003
Equity-based compensation	18,146			18,146
Distributions	(322,403)			(322,403)
Charges to partners' equity for accrued distribution equivalent rights	(2,049)			(2,049)
Distributions on Series B cumulative convertible preferred units		(21,000)			(21,000)
Net income (loss)	476,480			476,480
Ending balance (in shares) at Dec. 31, 2022			209,407
Ending balance at Dec. 31, 2022	911,451			911,451
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common and subordinated units (in shares)			(358)
Repurchases of common units	(5,496)			(5,496)
Restricted units granted, net of forfeitures (in shares)			942
Equity-based compensation	12,525			12,525
Distributions	(398,824)			(398,824)
Charges to partners' equity for accrued distribution equivalent rights	(2,221)			(2,221)
Distributions on Series B cumulative convertible preferred units		$ (21,776)			$ (21,776)
Net income (loss)	422,549			422,549
Ending balance (in shares) at Dec. 31, 2023			209,991
Ending balance at Dec. 31, 2023	$ 918,208			$ 918,208

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 422,549	$ 476,480	$ 181,987
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	45,683	47,804	61,019
Accretion of asset retirement obligations	1,042	861	1,073
Amortization of deferred charges	1,039	1,954	1,579
(Gain) loss on commodity derivative instruments	(91,117)	120,680	146,474
Net cash (paid) received on settlement of commodity derivative instruments	82,723	(203,166)	(112,946)
Equity-based compensation	10,829	17,388	12,218
Exploratory dry hole expense	0	0	1,048
(Gain) loss on sale of assets, net	(73)	(17)	(2,850)
Changes in operating assets and liabilities:
Accounts receivable	53,053	(39,513)	(34,856)
Prepaid expenses and other current assets	(414)	51	(289)
Accounts payable, accrued liabilities, and other	(3,827)	3,012	2,652
Settlement of asset retirement obligations	(236)	(551)	(229)
NET CASH PROVIDED BY OPERATING ACTIVITIES	521,251	424,983	256,880
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(14,605)	(149)	(10,043)
Additions to oil and natural gas properties	(4,213)	(11,894)	(4,066)
Additions to oil and natural gas properties leasehold costs	(545)	(32)	(98)
Purchases of other property and equipment	(450)	(488)	(428)
Proceeds from the sale of oil and natural gas properties	73	17	318
Proceeds from farmouts of oil and natural gas properties	0	11,331	0
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(19,740)	(1,215)	(14,317)
CASH FLOWS FROM FINANCING ACTIVITIES
Repurchases of common units	(5,496)	(2,991)	(1,957)
Borrowings under credit facility	64,000	339,000	212,000
Repayments under credit facility	(74,000)	(418,000)	(244,000)
Debt issuance costs and other	(216)	(2,943)	(3,602)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(435,536)	(428,337)	(235,483)
NET CHANGE IN CASH AND CASH EQUIVALENTS	65,975	(4,569)	7,080
Cash and cash equivalents — beginning of the year	4,307	8,876	1,796
Cash and cash equivalents — end of the year	70,282	4,307	8,876
SUPPLEMENTAL DISCLOSURE
Interest paid	1,736	4,332	4,035
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(398,824)	(322,403)	(176,924)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (21,000)	$ (21,000)	$ (21,000)

Business and Basis of Presentat

Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2023
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. 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"). 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, 2023
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 estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, 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, 2023 2022 (in thousands) Accounts receivable: Revenues from contracts with customers $ 77,560 $ 129,078 Other 4,693 6,619 Total accounts receivable $ 82,253 $ 135,697 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 additional information. 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 additional information. 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 leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"). The basis for grouping is a reasonable aggregation of properties with a common geographic location, 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 $45.0 million, $47.2 million, and $60.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. The Partnership evaluates impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. There was no impairment of proved or unproved oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021. See "Note 6 - Fair Value Measurements" for additional information. 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 $0.7 million, $0.6 million, and $0.6 million for the years ended December 31, 2023, 2022, and 2021, 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, 2023 2022 (in thousands) Accrued liabilities: Accrued capital expenditures $ 5 $ 162 Accrued incentive compensation 8,041 10,050 Accrued property taxes 6,378 7,431 Accrued other 2,579 2,086 Total accrued liabilities $ 17,003 $ 19,729 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, $2.0 million, and $1.6 million for the years ended December 31, 2023, 2022, and 2021, 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 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, 2023 and 2022, none of the Partnership’s leases were classified as financing leases. Right-of-use ("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. 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. 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. 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, 2023 and 2022, 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, 2023 and 2022 due to the short-term maturity of these instruments. See "Note 6 – Fair Value Measurements" for additional information. 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 the General and administrative line item on the consolidated statements of operations. See "Note 9 – Incentive Compensation" for additional information. Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures ( Topic 280

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS The asset retirement obligation ("ARO") liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of 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, 2023 2022 (in thousands) Beginning asset retirement obligations $ 16,019 $ 13,284 Liabilities incurred 174 124 Liabilities settled (98) (294) Accretion expense 1,042 861 Revisions in estimated costs 3,130 2,044 Dispositions — — Ending asset retirement obligations $ 20,267 $ 16,019 Current asset retirement obligations $ 1,237 $ 989 Non-current asset retirement obligations $ 19,030 $ 15,030

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Oil and Natural Gas Properties	OIL AND NATURAL GAS PROPERTIES Divestitures The Partnership had no material divestiture activity during 2023 and 2022. In the third quarter of 2021, the Partnership closed on the divestiture of its wholly owned subsidiary, TLW Investments, L.L.C. ("TLW"), effective September 1, 2021 for total proceeds of $0.2 million. TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas. TLW's assets and liabilities consisted of oil and natural gas properties with a net book value of $3.0 million and asset retirement obligations with a book value of $5.7 million at the time of sale. The Partnership recognized a $2.9 million gain associated with the divestiture included in the (Gain) loss on sale of assets Acquisitions 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. 2023 Acquisitions During the year ended December 31, 2023, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for cash consideration of $14.6 million, including capitalized direct transaction costs. The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region. 2022 Acquisitions The Partnership had no material acquisition activity during 2022. 2021 Acquisitions In May 2021, the Partnership closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units of the Partnership. The cash consideration was funded with borrowings under the Credit Facility (as defined in Note 8 - Credit Facility) and funds from operating activities. The transaction was accounted for as a business combination with the assets acquired recorded at their estimated fair values as of the acquisition date. The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital. Acquisition related costs of $0.3 million were expensed and included in the General and administrative line of the consolidated statement of operations for the year ended December 31, 2021. Farmout Agreements The Partnership has entered into 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. San Augustine Farmout In March 2021, BSM and XTO reached an agreement to partition jointly owned working interests in the Brent Miller development area in San Augustine County. Under the partition agreement, BSM and XTO exchanged working interests in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units. In May 2021, BSM and Aethon Energy ("Aethon") entered into an agreement to develop certain of the Partnership's undeveloped acreage in San Augustine County, including the working interests resulting from the partition agreement discussed above. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which began in the third quarter of 2021, 10 wells to be drilled in the second and third program years, and, thereafter, a minimum of 12 wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County discussed below. In May 2021, the Partnership entered into a new farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). In April 2022, the Partnership amended the Canaan Farmout and entered into a farmout agreement (the "JWM Farmout") with JWM Oil & Gas LLC ("JWM"). These agreements cover all of the Partnership's working interests under active development by Aethon in San Augustine County, Texas and continue for a 10 year period, unless earlier terminated in accordance with the terms of the agreements. Canaan, Azul, and JWM will each earn a percentage of the Partnership's working interest in wells drilled and operated by Aethon within the contract area subject to the agreements. Canaan, Azul, and JWM were obligated to fund the development of wells drilled by Aethon in the initial program year, and thereafter, have certain rights and options to continue funding the Partnership's working interest for the duration of each farmout agreement. The Partnership will receive an overriding royalty interest ("ORRI") before payout and, in most cases, an increased ORRI after payout on all wells drilled under the farmout agreements. As of December 31, 2023, 17 wells had been spud in the contract area subject to the Canaan, Azul, and JWM Farmouts. The following tables present the working interests each farmout partner will earn within the contract area under the San Augustine farmout agreements: Brent Miller Area Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis Canaan 64.0 % 32.0 % Azul 20.0 % 10.0 % JWM 16.0 % 8.0 % Total 100.0 % 50.0 % Other Areas Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis Canaan 40.0 % 10.0 % Azul 50.0 % 12.5 % JWM 10.0 % 2.5 % Total 100.0 % 25.0 % Angelina Farmout In May 2020, the Partnership entered into a development agreement with Aethon to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, 10 wells to be drilled in the second program year, and, beginning with the third program year, 15 wells per year beginning thereafter. In November 2020, the Partnership entered into a new farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal was obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Pivotal Farmout. 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. As of December 31, 2023, a total of 45 wells have been spud in the contract area subject to the Pivotal Farmout. Aethon Time-Out In December 2023, the Partnership received notice that Aethon was exercising the "time-out" provisions under its joint exploration agreements with BSM in Angelina and San Augustine counties in East Texas. When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. The current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months. Aethon has not previously invoked the time-out provisions under the agreements. Impairment of Oil and Natural Gas Properties 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 compared 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. No impairment of oil and natural gas properties was recognized for the years ended December 31, 2023, 2022, and 2021. See "Note 6 - Fair Value Measurements" for additional information.

Commodity Derivative Financial

Commodity Derivative Financial Instruments Instruments	12 Months Ended
	Dec. 31, 2023
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. 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 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, 2023 and 2022, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts. 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, 2023 and 2022. See "Note 6 – Fair Value Measurements" for additional information. 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, 2023, the Partnership had seven counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under the 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, 2023 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 $ 41,485 $ (3,212) $ 38,273 Long-term asset Deferred charges and other long-term assets 498 (126) 372 Total assets $ 41,983 $ (3,338) $ 38,645 Liabilities: Current liability Commodity derivative liabilities $ 4,441 $ (3,212) $ 1,229 Long-term liability Commodity derivative liabilities 207 (126) 81 Total liabilities $ 4,648 $ (3,338) $ 1,310 As of December 31, 2022 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 $ 41,648 $ (10,176) $ 31,472 Long-term asset Deferred charges and other long-term assets 797 (69) 728 Total assets $ 42,445 $ (10,245) $ 32,200 Liabilities: Current liability Commodity derivative liabilities $ 13,419 $ (10,176) $ 3,243 Long-term liability Commodity derivative liabilities 85 (69) 16 Total liabilities $ 13,504 $ (10,245) $ 3,259 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 2023 2022 2021 (in thousands) Beginning fair value of commodity derivative instruments $ 28,941 $ (53,545) $ (20,017) Gain (loss) on oil derivative instruments 3,888 (46,890) (75,180) Gain (loss) on natural gas derivative instruments 87,229 (73,790) (71,294) Net cash paid (received) on settlements of oil derivative instruments (2,653) 77,790 66,418 Net cash paid (received) on settlements of natural gas derivative instruments (80,070) 125,376 46,528 Net change in fair value of commodity derivative instruments 8,394 82,486 (33,528) Ending fair value of commodity derivative instruments $ 37,335 $ 28,941 $ (53,545) The Partnership had the following open derivative contracts for oil as of December 31, 2023: Volume (MBbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2023 Fourth quarter 180 $ 80.80 $ 73.00 $ 89.50 2024 First quarter 570 71.45 67.00 81.00 Second quarter 570 71.45 67.00 81.00 Third quarter 570 71.45 67.00 81.00 Fourth quarter 570 71.45 67.00 81.00 The Partnership had the following open derivative contracts for natural gas as of December 31, 2023: Volume (BBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2024 First quarter 10,010 $ 3.57 $ 3.48 $ 3.76 Second quarter 10,010 3.57 3.48 3.76 Third quarter 10,120 3.57 3.48 3.76 Fourth quarter 10,120 3.57 3.48 3.76 The Partnership had the following open derivative contracts for oil subsequent to December 31, 2023: Volume (MBbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2025 First quarter 210 $ 70.50 $ 70.16 $ 70.75 Second quarter 210 70.50 70.16 70.75 Third quarter 210 70.50 70.16 70.75 Fourth quarter 210 70.50 70.16 70.75 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2023: Volume (BBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2024 First quarter 300 $ 3.00 $ 3.00 $ 3.00 Second quarter 455 3.00 3.00 3.00 Third quarter 460 3.00 3.00 3.00 Fourth quarter 460 3.00 3.00 3.00 2025 First quarter 900 3.65 3.65 3.65 Second quarter 910 3.65 3.65 3.65 Third quarter 920 3.65 3.65 3.65 Fourth quarter 920 3.65 3.65 3.65

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurements	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, 2023 and 2022. 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, 2023 and 2022 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 additional information. 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 Level 1 Level 2 Level 3 Counterparty Netting Total (in thousands) As of December 31, 2023 Financial Assets Commodity derivative instruments $ — $ 41,983 $ — $ (3,338) $ 38,645 Financial Liabilities Commodity derivative instruments — 4,648 — (3,338) 1,310 As of December 31, 2022 Financial Assets Commodity derivative instruments $ — $ 42,445 $ — $ (10,245) $ 32,200 Financial Liabilities Commodity derivative instruments — 13,504 — (10,245) 3,259 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 non-recurring 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. This evaluation is performed on a depletable unit basis. When assessing producing properties for impairment, 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. When assessing unproved properties for impairment, an impairment loss is recognized to the extent the carrying value within a depletable unit 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. 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, 2023 and 2022. There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2023 and 2022.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Significant Customers	SIGNIFICANT CUSTOMERS The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. XTO Energy represented approximately 12% and 19% of total oil and natural gas revenue for the years ended December 31, 2022 and 2021, respectively. No customer exceeded 10% of total oil and natural gas revenue for the year ended December 31, 2023. 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, 2023
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. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. 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. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base. In October 2022, the Partnership revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and the Partnership elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $580.0 million. After both redeterminations the Partnership elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2024. In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR"). Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50%, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or Adjusted Term SOFR, in each case, plus the applicable margin. As of December 31, 2023 and 2022, the alternative base rate margin ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin ranged from 2.50% to 3.50% depending on the borrowings outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary SOFR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. The weighted-average interest rate of the Credit Facility was 7.36% during the twelve months ended December 31, 2023 and the weighted-average interest rate was 6.92% as of December 31, 2022. 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. 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. Distributions are not permitted if there is a default under the credit agreement (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0. As of December 31, 2023, the Partnership was in compliance with all financial covenants in the Credit Facility. At December 31, 2023, there was no aggregate principal balance outstanding and the aggregate principal balance outstanding at December 31, 2022 was $10.0 million. The unused portion of the available borrowings under the Credit Facility were $375.0 million and $365.0 million at December 31, 2023 and 2022, respectively.

Incentive Compensation

Incentive Compensation	12 Months Ended
	Dec. 31, 2023
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 the General and administrative line item on the consolidated statements of operations. The total compensation expense related to common unit grants is measured as the number of units granted 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) with actual forfeitures recognized as they occur. Cash Awards The Partnership also provides cash incentives in the form of an annual short-term incentive bonus for its executive officers and other employees. These awards are payable based on employee performance and the achievement of annual financial objectives measured against our internal operating plan established at the beginning of each fiscal year. However, final payouts are subject to reduction or increase by the Compensation Committee for individual and team performance during the performance period. 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 is recognized ratably using the straight-line attribution method. 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 2023 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2026. 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, 2023. Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 823,278 $ 10.72 Granted 284,772 16.03 Vested (400,139) 10.40 Forfeited (110,736) 11.18 Unvested at December 31, 2023 597,175 13.38 The weighted-average grant-date fair value per unit for unit-based awards was $16.03, $12.00, and $9.25 for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, unrecognized compensation cost associated with restricted unit awards was $4.3 million, which the Partnership expects to recognize over a weighted-average period of 1.72 years. The fair value of units vested for the years ended December 31, 2023, 2022, and 2021 was $6.2 million, $4.0 million, and $2.3 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2023, 2022, and 2021. 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 The following table summarizes information about performance units for the year ended December 31, 2023. Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 1,175,529 $ 10.40 Granted 1 376,832 14.54 Vested (520,574) 9.98 Forfeited (109,748) 11.20 Unvested at December 31, 2023 922,039 12.24 1 Includes 92,060 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 $14.54, $12.40, and $9.61 for the years ended December 31, 2023, 2022, and 2021, respectively. Unrecognized compensation cost associated with performance unit awards was $4.9 million as of December 31, 2023, which the Partnership expects to recognize over a weighted-average period of 1.64 years. The fair value of performance units vested for the years ended December 31, 2023, 2022 and 2021 was $8.0 million, $3.9 million and $2.8 million, respectively. Aspirational Performance Unit Awards In the first quarter of 2022, the Board approved a grant of awards to all employees dependent on the achievement of an aspirational production target to be measured in the fourth quarter of 2025 (the "Aspirational Awards"). The Aspirational Awards include performance cash awards and performance equity awards in the form of restricted performance units. To the extent earned, each performance unit represents the right to receive one common unit. The performance cash awards and performance units are eligible to become earned at the end of the requisite service period on December 31, 2025 if the minimum performance metrics are achieved. The minimum performance metrics are at least 42 Mboe per day of average daily royalty production in either the fourth quarter or the month of December of 2025 while maintaining a net debt to EBITDA ratio less than or equal to 1.0 on December 31, 2025. Average daily royalty production does not include production attributable to acquisitions consummated during the performance period. The following table summarizes information about the aspirational performance units for the year ended December 31, 2023. Aspirational Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 1,412,008 $ 11.58 Granted 123,308 16.62 Vested — — Forfeited (261,803) 11.63 Unvested at December 31, 2023 1,273,513 12.06 Total compensation expense to be recognized over the life of the Aspirational Awards consists of $5.8 million for the performance cash awards and $15.4 million for the performance equity awards. Compensation expense related to the Aspirational Awards will be recorded over the service period when achievement of the performance condition is probable. As of December 31, 2023, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized. 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, 2023, 2022, and 2021. Year Ended December 31, Incentive compensation expense 2023 2022 2021 (in thousands) Cash — short and long-term incentive plan $ 4,442 $ 7,095 $ 6,824 Equity-based compensation — restricted common units 3,852 4,089 4,146 Equity-based compensation — restricted performance units 4,774 11,174 6,320 Board of Directors incentive plan 2,203 2,125 1,752 Total incentive compensation expense $ 15,271 $ 24,483 $ 19,042

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS Black Stone Natural Resources Management Company, a subsidiary of the Partnership, sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred pre-tax or post-tax 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 years of service with the Partnership. Following three years of service, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.6 million, $0.6 million, and $0.5 million for the years ended December 31, 2023, 2022, and 2021, respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
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. Litigation

Preferred Units

Preferred Units	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Preferred Units	PREFERRED UNITS 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 $20.39 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million. The Series B cumulative convertible preferred units were initially entitled to quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”). On November 28, 2023, the Distribution Rate was adjusted to 9.8% and will be readjusting every two years thereafter (each, a “Readjustment Date”). The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter. The Partnership cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions. 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 $20.39, 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 $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Partnership has the option to redeem all or a portion (equal to or greater than $100.0 million) of the Series B cumulative convertible preferred units until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value. Thereafter, the Partnership may redeem the Series B cumulative convertible preferred units at par within a 90-day period on each second anniversary following November 28, 2023. The Series B cumulative convertible preferred units had a carrying value of $299.1 million, including accrued distributions of $6.0 million, as of December 31, 2023 and a carrying value of $298.4 million, including accrued distributions of $5.3 million as of December 31, 2022. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain redemption provisions are outside the control of the Partnership.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2023
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 unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Partnership assesses 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, 2023 2022 2021 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 422,549 $ 476,480 $ 181,987 Distributions on Series B cumulative convertible preferred units (21,776) (21,000) (21,000) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 400,773 $ 455,480 $ 160,987 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 400,773 455,480 160,987 $ 400,773 $ 455,480 $ 160,987 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 400,773 $ 455,480 $ 160,987 Effect of dilutive securities 21,776 21,000 — Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 422,549 $ 476,480 $ 160,987 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 209,970 209,382 208,181 Effect of dilutive securities 15,135 15,064 109 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 225,105 224,446 208,290 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 1.91 $ 2.18 $ 0.77 Per common unit (diluted) 1.88 2.12 0.77 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, 2023 2022 2021 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis — — 14,968

Common Units

Common Units	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Common Units	COMMON UNITS The common units represent limited partner interests in the Partnership. The holders of common units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units under the partnership agreement. 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 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 7.0% of the face amount of the preferred units per annum, through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter; and • second , to the holders of common units. The following table provides information about the Partnership's per unit distributions to common unitholders: Year Ended December 31, 2023 2022 2021 Distributions declared and paid per common unit $ 1.90 $ 1.54 $ 0.85 Common Unit Repurchase Program On October 30, 2023, the Board authorized a $150.0 million unit repurchase program, terminating its existing $75.0 million program authorized in 2018. The unit repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market condition, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the year ended December 31, 2023. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Distribution On January 31, 2024, the Board approved a distribution for the period from October 1, 2023 to December 31, 2023 of $0.475 per common unit. Distributions will be paid on February 23, 2024 to unitholders of record at the close of business on February 16, 2024.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Disclosures	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 (in thousands) Acquisition Costs of Properties 1 : Proved $ — $ — $ 4,965 Unproved 14,605 149 15,559 Exploration Costs — — 1,049 Development Costs 1 4,601 11,293 3,964 Total $ 19,206 $ 11,442 $ 25,537 1 Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements. See "Note 4 – Oil and Natural Gas Properties" for additional information. 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, 2023 2022 (in thousands) Proved properties $ 2,136,056 $ 2,094,563 Unproved properties 890,338 909,344 Total 3,026,394 3,003,907 Accumulated depreciation, depletion, amortization, and impairment (1,961,899) (1,916,919) Oil and natural gas properties, net $ 1,064,495 $ 1,086,988 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. 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. For estimates of oil reserves, the average WTI spot oil prices used were $78.21, $94.14, and $66.55 per barrel as of December 31, 2023, 2022, and 2021, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $2.64, $6.36, and $3.60 per MMBtu as of December 31, 2023, 2022, and 2021, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties were $76.90 per barrel for oil and $2.63 per Mcf for natural gas as of December 31, 2023, $92.01 per barrel for oil and $6.50 per Mcf for natural gas as of December 31, 2022, and $63.17 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2021. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2020 15,952 240,211 55,987 Revisions of previous estimates 1 4,817 38,537 11,240 Purchases of minerals in place 2 272 216 308 Sales of minerals in place 4 (135) (6,194) (1,167) Extensions, discoveries and other additions 3 1,911 32,592 7,343 Production (3,646) (61,445) (13,886) Net proved reserves at December 31, 2021 19,171 243,917 59,824 Revisions of previous estimates 1 1,422 6,455 2,498 Extensions, discoveries and other additions 3 2,182 78,992 15,347 Production (3,591) (59,778) (13,554) Net proved reserves at December 31, 2022 19,184 269,586 64,115 Revisions of previous estimates 1 675 (20,578) (2,754) Extensions, discoveries and other additions 3 2,989 87,935 17,645 Production (3,757) (64,647) (14,532) Net proved reserves at December 31, 2023 19,091 272,296 64,474 Net Proved Developed Reserves December 31, 2021 19,111 224,222 56,481 December 31, 2022 19,184 236,529 58,606 December 31, 2023 19,091 228,061 57,101 Net Proved Undeveloped Reserves December 31, 2021 60 19,695 3,343 December 31, 2022 — 33,057 5,509 December 31, 2023 — 44,235 7,373 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable revisions are related to changes in commodity pricing. 2 Includes the acquisition of mineral and royalty reserves. In 2021 these were primarily in the Permian Basin. 3 Includes extensions and additions related to drilling activities in multiple areas, primarily within the Haynesville/Bossier play trend and the Permian Basin. 4 Includes divestitures of mineral and royalty reserves. In 2021 these were primarily in the Anadarko Basin. 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 additional information. Year Ended December 31, 2023 2022 2021 (in thousands) Future cash inflows $ 2,184,038 $ 3,518,494 $ 2,033,256 Future production costs (211,826) (339,603) (206,785) Future development costs (61,723) (49,081) (43,500) Future income tax expense (6,259) (10,535) (6,322) Future net cash flows (undiscounted) 1,904,230 3,119,275 1,776,649 Annual discount 10% for estimated timing (884,720) (1,454,264) (804,527) Total $ 1,019,510 $ 1,665,011 $ 972,122 The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2023 2022 2021 (in thousands) Standardized measure, beginning of year $ 1,665,011 $ 972,122 $ 493,497 Sales, net of production costs (420,228) (692,629) (428,577) Net changes in prices and production costs related to future production (649,695) 773,189 537,659 Extensions, discoveries and improved recovery, net of future production and development costs 295,413 476,342 148,732 Previously estimated development costs incurred during the period — 854 245 Revisions of estimated future development costs (4,221) (1,986) 2,254 Revisions of previous quantity estimates, net of related costs (78,139) 68,270 210,039 Accretion of discount 167,064 97,553 49,530 Purchases of reserves in place, less related costs — — 9,254 Sales of reserves in place — — (1,037) Changes in timing and other 44,305 (28,704) (49,474) Net increase (decrease) in standardized measures (645,501) 692,889 478,625 Standardized measure, end of year $ 1,019,510 $ 1,665,011 $ 972,122 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.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss)	$ 422,549	$ 476,480	$ 181,987

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
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 estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts Receivable	Accounts Receivable The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.
Commodity Derivative Financial Instruments	Commodity Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments.
Concentration of Credit Risk	Concentration of Credit Risk Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. The Partnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See "Note 7 – Significant Customers" for additional information.
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 leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"). The basis for grouping is a reasonable aggregation of properties with a common geographic location, 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 $45.0 million, $47.2 million, and $60.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. The Partnership evaluates impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. There was no impairment of proved or unproved oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021. See "Note 6 - Fair Value Measurements" for additional information. 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
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
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 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, 2023 and 2022, none of the Partnership’s leases were classified as financing leases. Right-of-use ("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	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. 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. 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. 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, 2023 and 2022, 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, 2023 and 2022 due to the short-term maturity of these instruments. See "Note 6 – Fair Value Measurements" for additional information.
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 the General and administrative line item on the consolidated statements of operations. See "Note 9 – Incentive Compensation" for additional information.
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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures ( Topic 280

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Schedule of Accounts Receivable	The following table presents information about the Partnership's accounts receivable: December 31, 2023 2022 (in thousands) Accounts receivable: Revenues from contracts with customers $ 77,560 $ 129,078 Other 4,693 6,619 Total accounts receivable $ 82,253 $ 135,697
Schedule of Accrued Liabilities	Accrued liabilities consisted of the following: December 31, 2023 2022 (in thousands) Accrued liabilities: Accrued capital expenditures $ 5 $ 162 Accrued incentive compensation 8,041 10,050 Accrued property taxes 6,378 7,431 Accrued other 2,579 2,086 Total accrued liabilities $ 17,003 $ 19,729

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 (in thousands) Beginning asset retirement obligations $ 16,019 $ 13,284 Liabilities incurred 174 124 Liabilities settled (98) (294) Accretion expense 1,042 861 Revisions in estimated costs 3,130 2,044 Dispositions — — Ending asset retirement obligations $ 20,267 $ 16,019 Current asset retirement obligations $ 1,237 $ 989 Non-current asset retirement obligations $ 19,030 $ 15,030

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Schedule of Working Interests	The following tables present the working interests each farmout partner will earn within the contract area under the San Augustine farmout agreements: Brent Miller Area Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis Canaan 64.0 % 32.0 % Azul 20.0 % 10.0 % JWM 16.0 % 8.0 % Total 100.0 % 50.0 % Other Areas Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis Canaan 40.0 % 10.0 % Azul 50.0 % 12.5 % JWM 10.0 % 2.5 % Total 100.0 % 25.0 %

Commodity Derivative Financia_2

Commodity Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 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 $ 41,485 $ (3,212) $ 38,273 Long-term asset Deferred charges and other long-term assets 498 (126) 372 Total assets $ 41,983 $ (3,338) $ 38,645 Liabilities: Current liability Commodity derivative liabilities $ 4,441 $ (3,212) $ 1,229 Long-term liability Commodity derivative liabilities 207 (126) 81 Total liabilities $ 4,648 $ (3,338) $ 1,310 As of December 31, 2022 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 $ 41,648 $ (10,176) $ 31,472 Long-term asset Deferred charges and other long-term assets 797 (69) 728 Total assets $ 42,445 $ (10,245) $ 32,200 Liabilities: Current liability Commodity derivative liabilities $ 13,419 $ (10,176) $ 3,243 Long-term liability Commodity derivative liabilities 85 (69) 16 Total liabilities $ 13,504 $ (10,245) $ 3,259
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 2023 2022 2021 (in thousands) Beginning fair value of commodity derivative instruments $ 28,941 $ (53,545) $ (20,017) Gain (loss) on oil derivative instruments 3,888 (46,890) (75,180) Gain (loss) on natural gas derivative instruments 87,229 (73,790) (71,294) Net cash paid (received) on settlements of oil derivative instruments (2,653) 77,790 66,418 Net cash paid (received) on settlements of natural gas derivative instruments (80,070) 125,376 46,528 Net change in fair value of commodity derivative instruments 8,394 82,486 (33,528) Ending fair value of commodity derivative instruments $ 37,335 $ 28,941 $ (53,545)
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of December 31, 2023: Volume (MBbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2023 Fourth quarter 180 $ 80.80 $ 73.00 $ 89.50 2024 First quarter 570 71.45 67.00 81.00 Second quarter 570 71.45 67.00 81.00 Third quarter 570 71.45 67.00 81.00 Fourth quarter 570 71.45 67.00 81.00 The Partnership had the following open derivative contracts for natural gas as of December 31, 2023: Volume (BBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2024 First quarter 10,010 $ 3.57 $ 3.48 $ 3.76 Second quarter 10,010 3.57 3.48 3.76 Third quarter 10,120 3.57 3.48 3.76 Fourth quarter 10,120 3.57 3.48 3.76 The Partnership had the following open derivative contracts for oil subsequent to December 31, 2023: Volume (MBbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2025 First quarter 210 $ 70.50 $ 70.16 $ 70.75 Second quarter 210 70.50 70.16 70.75 Third quarter 210 70.50 70.16 70.75 Fourth quarter 210 70.50 70.16 70.75 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2023: Volume (BBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2024 First quarter 300 $ 3.00 $ 3.00 $ 3.00 Second quarter 455 3.00 3.00 3.00 Third quarter 460 3.00 3.00 3.00 Fourth quarter 460 3.00 3.00 3.00 2025 First quarter 900 3.65 3.65 3.65 Second quarter 910 3.65 3.65 3.65 Third quarter 920 3.65 3.65 3.65 Fourth quarter 920 3.65 3.65 3.65

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2023
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 Level 1 Level 2 Level 3 Counterparty Netting Total (in thousands) As of December 31, 2023 Financial Assets Commodity derivative instruments $ — $ 41,983 $ — $ (3,338) $ 38,645 Financial Liabilities Commodity derivative instruments — 4,648 — (3,338) 1,310 As of December 31, 2022 Financial Assets Commodity derivative instruments $ — $ 42,445 $ — $ (10,245) $ 32,200 Financial Liabilities Commodity derivative instruments — 13,504 — (10,245) 3,259

Incentive Compensation (Tables)

Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023. Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 823,278 $ 10.72 Granted 284,772 16.03 Vested (400,139) 10.40 Forfeited (110,736) 11.18 Unvested at December 31, 2023 597,175 13.38
Summary of Information about Performance Units	The following table summarizes information about performance units for the year ended December 31, 2023. Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 1,175,529 $ 10.40 Granted 1 376,832 14.54 Vested (520,574) 9.98 Forfeited (109,748) 11.20 Unvested at December 31, 2023 922,039 12.24 1 Includes 92,060 of additional performance units issued based on the final performance multiplier for awards that vested in the period.
Summary of Aspirational Performance Unit Awards	The following table summarizes information about the aspirational performance units for the year ended December 31, 2023. Aspirational Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2022 1,412,008 $ 11.58 Granted 123,308 16.62 Vested — — Forfeited (261,803) 11.63 Unvested at December 31, 2023 1,273,513 12.06
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, 2023, 2022, and 2021. Year Ended December 31, Incentive compensation expense 2023 2022 2021 (in thousands) Cash — short and long-term incentive plan $ 4,442 $ 7,095 $ 6,824 Equity-based compensation — restricted common units 3,852 4,089 4,146 Equity-based compensation — restricted performance units 4,774 11,174 6,320 Board of Directors incentive plan 2,203 2,125 1,752 Total incentive compensation expense $ 15,271 $ 24,483 $ 19,042

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 422,549 $ 476,480 $ 181,987 Distributions on Series B cumulative convertible preferred units (21,776) (21,000) (21,000) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 400,773 $ 455,480 $ 160,987 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 400,773 455,480 160,987 $ 400,773 $ 455,480 $ 160,987 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 400,773 $ 455,480 $ 160,987 Effect of dilutive securities 21,776 21,000 — Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 422,549 $ 476,480 $ 160,987 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 209,970 209,382 208,181 Effect of dilutive securities 15,135 15,064 109 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 225,105 224,446 208,290 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 1.91 $ 2.18 $ 0.77 Per common unit (diluted) 1.88 2.12 0.77
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	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, 2023 2022 2021 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis — — 14,968

Common Units (Tables)

Common Units (Tables)	12 Months Ended
	Dec. 31, 2023
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 unitholders: Year Ended December 31, 2023 2022 2021 Distributions declared and paid per common unit $ 1.90 $ 1.54 $ 0.85

Supplemental Oil and Natural _2

Supplemental Oil and Natural Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 (in thousands) Acquisition Costs of Properties 1 : Proved $ — $ — $ 4,965 Unproved 14,605 149 15,559 Exploration Costs — — 1,049 Development Costs 1 4,601 11,293 3,964 Total $ 19,206 $ 11,442 $ 25,537 1 Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements. See "Note 4 – Oil and Natural Gas Properties" for additional information.
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, 2023 2022 (in thousands) Proved properties $ 2,136,056 $ 2,094,563 Unproved properties 890,338 909,344 Total 3,026,394 3,003,907 Accumulated depreciation, depletion, amortization, and impairment (1,961,899) (1,916,919) Oil and natural gas properties, net $ 1,064,495 $ 1,086,988
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. 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. For estimates of oil reserves, the average WTI spot oil prices used were $78.21, $94.14, and $66.55 per barrel as of December 31, 2023, 2022, and 2021, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $2.64, $6.36, and $3.60 per MMBtu as of December 31, 2023, 2022, and 2021, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties were $76.90 per barrel for oil and $2.63 per Mcf for natural gas as of December 31, 2023, $92.01 per barrel for oil and $6.50 per Mcf for natural gas as of December 31, 2022, and $63.17 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2021. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2020 15,952 240,211 55,987 Revisions of previous estimates 1 4,817 38,537 11,240 Purchases of minerals in place 2 272 216 308 Sales of minerals in place 4 (135) (6,194) (1,167) Extensions, discoveries and other additions 3 1,911 32,592 7,343 Production (3,646) (61,445) (13,886) Net proved reserves at December 31, 2021 19,171 243,917 59,824 Revisions of previous estimates 1 1,422 6,455 2,498 Extensions, discoveries and other additions 3 2,182 78,992 15,347 Production (3,591) (59,778) (13,554) Net proved reserves at December 31, 2022 19,184 269,586 64,115 Revisions of previous estimates 1 675 (20,578) (2,754) Extensions, discoveries and other additions 3 2,989 87,935 17,645 Production (3,757) (64,647) (14,532) Net proved reserves at December 31, 2023 19,091 272,296 64,474 Net Proved Developed Reserves December 31, 2021 19,111 224,222 56,481 December 31, 2022 19,184 236,529 58,606 December 31, 2023 19,091 228,061 57,101 Net Proved Undeveloped Reserves December 31, 2021 60 19,695 3,343 December 31, 2022 — 33,057 5,509 December 31, 2023 — 44,235 7,373 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable revisions are related to changes in commodity pricing. 2 Includes the acquisition of mineral and royalty reserves. In 2021 these were primarily in the Permian Basin. 3 Includes extensions and additions related to drilling activities in multiple areas, primarily within the Haynesville/Bossier play trend and the Permian Basin. 4 Includes divestitures of mineral and royalty reserves. In 2021 these were primarily in the Anadarko Basin.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2023 2022 2021 (in thousands) Future cash inflows $ 2,184,038 $ 3,518,494 $ 2,033,256 Future production costs (211,826) (339,603) (206,785) Future development costs (61,723) (49,081) (43,500) Future income tax expense (6,259) (10,535) (6,322) Future net cash flows (undiscounted) 1,904,230 3,119,275 1,776,649 Annual discount 10% for estimated timing (884,720) (1,454,264) (804,527) Total $ 1,019,510 $ 1,665,011 $ 972,122
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, 2023 2022 2021 (in thousands) Standardized measure, beginning of year $ 1,665,011 $ 972,122 $ 493,497 Sales, net of production costs (420,228) (692,629) (428,577) Net changes in prices and production costs related to future production (649,695) 773,189 537,659 Extensions, discoveries and improved recovery, net of future production and development costs 295,413 476,342 148,732 Previously estimated development costs incurred during the period — 854 245 Revisions of estimated future development costs (4,221) (1,986) 2,254 Revisions of previous quantity estimates, net of related costs (78,139) 68,270 210,039 Accretion of discount 167,064 97,553 49,530 Purchases of reserves in place, less related costs — — 9,254 Sales of reserves in place — — (1,037) Changes in timing and other 44,305 (28,704) (49,474) Net increase (decrease) in standardized measures (645,501) 692,889 478,625 Standardized measure, end of year $ 1,019,510 $ 1,665,011 $ 972,122

Business and Basis of Present_2

Business and Basis of Presentation - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 state segment
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20%
Number of operating segments	1
Number of reportable segments	1
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, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 82,253	$ 135,697
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	77,560	129,078
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 4,693	$ 6,619

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	$ 45,683,000	$ 47,804,000	$ 61,019,000
Impairment of oil and natural gas properties	0	0	0
Amortization of debt issuance costs	1,000,000	2,000,000	1,600,000
Oil and Natural Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	45,000,000	47,200,000	60,400,000
Proved Oil And Gas Properties
Summary Of Significant Accounting Polices [Line Items]
Impairment of oil and natural gas properties	0	0
Other Property and Equipment
Summary Of Significant Accounting Polices [Line Items]
Depreciation, depletion, and amortization	$ 700,000	$ 600,000	$ 600,000
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, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Accrued capital expenditures	$ 5	$ 162
Accrued incentive compensation	8,041	10,050
Accrued property taxes	6,378	7,431
Accrued other	2,579	2,086
Total accrued liabilities	$ 17,003	$ 19,729

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 16,019	$ 13,284
Liabilities incurred	174	124
Liabilities settled	(98)	(294)
Accretion expense	1,042	861	$ 1,073
Revisions in estimated costs	3,130	2,044
Dispositions	0	0
Ending asset retirement obligations	20,267	16,019	$ 13,284
Current asset retirement obligations	1,237	989
Non-current asset retirement obligations	$ 19,030	$ 15,030

Oil and Natural Gas Propertie_2

Oil and Natural Gas Properties - Divestitures (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Proceeds from divestures		$ 73	$ 17	$ 318
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]			Gain (Loss) on Disposition of Property Plant Equipment
Disposal Group, Held-for-sale, Not Discontinued Operations | TLW Investments
Business Acquisition [Line Items]
Proceeds from divestures	$ 200
Book value of divestures	3,000
Book value of asset retirement obligation	$ 5,700
Gain associated with divestures			$ 2,900

Oil and Natural Gas Propertie_3

Oil and Natural Gas Properties - Acquisitions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	May 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Proved oil and natural gas properties		$ 0	$ 0	$ 4,965
Unproved oil and natural gas properties		14,605	$ 149	15,559
Unproved Oil And Natural Gas Properties
Business Acquisition [Line Items]
Total consideration		$ 14,600
Mineral And Royalty Acreage In Northern Midland Basin
Business Acquisition [Line Items]
Total consideration	$ 20,800
Purchase price, cash	10,000
Common unit consideration for acquisition	10,800
Proved oil and natural gas properties	4,900
Unproved oil and natural gas properties	15,600
Net working capital	$ 300
Acquisition-related costs				$ 300

Oil and Natural Gas Propertie_4

Oil and Natural Gas Properties - Farmout Agreements Narrative (Details) - well	1 Months Ended		3 Months Ended		12 Months Ended
	Mar. 31, 2021	Nov. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Agreement period					10 years
Farmout Agreement | San Augustine County, Texas | XTO Energy Inc.
Business Acquisition [Line Items]
Partition agreement, ownership interest in partitioned drilling units, percent	100%
Farmout Agreement | San Augustine County, Texas | Aethon Energy
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled initial program year			5
Exploratory wells, expected to be drilled			10
Exploratory wells, expected to be drilled per year			12
Farmout Agreement | San Augustine County, Texas | Azul-SA, LLC and Canaan Resource Partners
Business Acquisition [Line Items]
Number of wells					17
Farmout Agreement | Angelina County, Texas | Aethon Energy
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled				4
Exploratory wells, expected to be drilled per year						15
Farmout Agreement | Angelina County, Texas | Pivotal
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled							10
Farmout Agreement | Angelina County, Texas | Second Pivotal Farmout
Business Acquisition [Line Items]
Number of wells					45
% of Partnership's Working Interest		100%
Farmout Agreement | Angelina County, Texas | Second Pivotal Farmout | Minimum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		12.50%
Farmout Agreement | Angelina County, Texas | Second Pivotal Farmout | Maximum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		25%

Oil and Natural Gas Propertie_5

Oil and Natural Gas Properties - San Augustine Farmout Agreements (Details)	1 Months Ended
	May 31, 2021
Partitioned Acreage From XTO
Business Acquisition [Line Items]
% of Partnership's Working Interest	100%
Maximum % on an 8/8th basis	50%
Other
Business Acquisition [Line Items]
% of Partnership's Working Interest	100%
Maximum % on an 8/8th basis	25%
Farmout Agreement | San Augustine County, Texas | Canaan | Partitioned Acreage From XTO
Business Acquisition [Line Items]
% of Partnership's Working Interest	64%
Farmout Agreement | San Augustine County, Texas | Canaan | Partitioned Acreage From XTO | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	32%
Farmout Agreement | San Augustine County, Texas | Canaan | Other
Business Acquisition [Line Items]
% of Partnership's Working Interest	40%
Farmout Agreement | San Augustine County, Texas | Canaan | Other | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	10%
Farmout Agreement | San Augustine County, Texas | Azul | Partitioned Acreage From XTO
Business Acquisition [Line Items]
% of Partnership's Working Interest	20%
Farmout Agreement | San Augustine County, Texas | Azul | Partitioned Acreage From XTO | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	10%
Farmout Agreement | San Augustine County, Texas | Azul | Other
Business Acquisition [Line Items]
% of Partnership's Working Interest	50%
Farmout Agreement | San Augustine County, Texas | Azul | Other | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	12.50%
Farmout Agreement | San Augustine County, Texas | JWM | Partitioned Acreage From XTO
Business Acquisition [Line Items]
% of Partnership's Working Interest	16%
Farmout Agreement | San Augustine County, Texas | JWM | Partitioned Acreage From XTO | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	8%
Farmout Agreement | San Augustine County, Texas | JWM | Other
Business Acquisition [Line Items]
% of Partnership's Working Interest	10%
Farmout Agreement | San Augustine County, Texas | JWM | Other | Maximum
Business Acquisition [Line Items]
Maximum % on an 8/8th basis	2.50%

Oil and Natural Gas Propertie_6

Oil and Natural Gas Properties - Impairment of Oil and Gas (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Impairment of oil and natural gas properties	$ 0	$ 0	$ 0

Commodity Derivative Financia_3

Commodity Derivative Financial Instruments - Narrative (Details)	Dec. 31, 2023 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	7

Commodity Derivative Financia_4

Commodity Derivative Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 41,983	$ 42,445
Effect of counterparty netting, assets	(3,338)	(10,245)
Net carrying value on balance sheet, assets	38,645	32,200
Gross fair value, liabilities	4,648	13,504
Effect of counterparty netting, liabilities	(3,338)	(10,245)
Net carrying value on balance sheet, liabilities	1,310	3,259
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	41,485	41,648
Effect of counterparty netting, assets	(3,212)	(10,176)
Net carrying value on balance sheet, assets	38,273	31,472
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	498	797
Effect of counterparty netting, assets	(126)	(69)
Net carrying value on balance sheet, assets	372	728
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	4,441	13,419
Effect of counterparty netting, liabilities	(3,212)	(10,176)
Net carrying value on balance sheet, liabilities	1,229	3,243
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	207	85
Effect of counterparty netting, liabilities	(126)	(69)
Net carrying value on balance sheet, liabilities	$ 81	$ 16

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	$ 91,117	$ (120,680)	$ (146,474)
Net cash paid (received) on settlements of derivative instruments	(82,723)	203,166	112,946
Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	28,941	(53,545)	(20,017)
Net change in fair value of commodity derivative instruments	8,394	82,486	(33,528)
Ending fair value of commodity derivative instruments	37,335	28,941	(53,545)
Oil | Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	3,888	(46,890)	(75,180)
Net cash paid (received) on settlements of derivative instruments	(2,653)	77,790	66,418
Natural gas and natural gas liquids sales | Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Gain (loss) on derivative instruments	87,229	(73,790)	(71,294)
Net cash paid (received) on settlements of derivative instruments	$ (80,070)	$ 125,376	$ 46,528

Commodity Derivative Financia_6

Commodity Derivative Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Derivatives not designated as hedging instruments - Swap - Swap Contracts MMBbls in Thousands, MMBTU in Thousands	2 Months Ended	12 Months Ended
	Feb. 20, 2024 MMBTU $ / MMBTU	Dec. 31, 2023 MMBTU $ / bbl $ / MMBTU MMBbls
Oil | Fourth Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		180
Derivative contract, weighted average price | $ / bbl		80.80
Derivative contract, price range low | $ / bbl		73
Derivative contract, price range high | $ / bbl		89.50
Oil | First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		570
Derivative contract, weighted average price | $ / bbl		71.45
Derivative contract, price range low | $ / bbl		67
Derivative contract, price range high | $ / bbl		81
Oil | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		570
Derivative contract, weighted average price | $ / bbl		71.45
Derivative contract, price range low | $ / bbl		67
Derivative contract, price range high | $ / bbl		81
Oil | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		570
Derivative contract, weighted average price | $ / bbl		71.45
Derivative contract, price range low | $ / bbl		67
Derivative contract, price range high | $ / bbl		81
Oil | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		570
Derivative contract, weighted average price | $ / bbl		71.45
Derivative contract, price range low | $ / bbl		67
Derivative contract, price range high | $ / bbl		81
Oil | First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		210
Derivative contract, weighted average price | $ / bbl		70.50
Derivative contract, price range low | $ / bbl		70.16
Derivative contract, price range high | $ / bbl		70.75
Oil | Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		210
Derivative contract, weighted average price | $ / bbl		70.50
Derivative contract, price range low | $ / bbl		70.16
Derivative contract, price range high | $ / bbl		70.75
Oil | Third Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		210
Derivative contract, weighted average price | $ / bbl		70.50
Derivative contract, price range low | $ / bbl		70.16
Derivative contract, price range high | $ / bbl		70.75
Oil | Fourth Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | MMBbls		210
Derivative contract, weighted average price | $ / bbl		70.50
Derivative contract, price range low | $ / bbl		70.16
Derivative contract, price range high | $ / bbl		70.75
Natural gas and natural gas liquids sales | First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,010
Derivative contract, weighted average price		3.57
Derivative contract, price range low		3.48
Derivative contract, price range high		3.76
Natural gas and natural gas liquids sales | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,010
Derivative contract, weighted average price		3.57
Derivative contract, price range low		3.48
Derivative contract, price range high		3.76
Natural gas and natural gas liquids sales | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,120
Derivative contract, weighted average price		3.57
Derivative contract, price range low		3.48
Derivative contract, price range high		3.76
Natural gas and natural gas liquids sales | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,120
Derivative contract, weighted average price		3.57
Derivative contract, price range low		3.48
Derivative contract, price range high		3.76
Subsequent Event | Oil and condensate sales | First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	300
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Subsequent Event | Oil and condensate sales | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	455
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Subsequent Event | Oil and condensate sales | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	460
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Subsequent Event | Oil and condensate sales | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	460
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Subsequent Event | Oil and condensate sales | First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	900
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Subsequent Event | Oil and condensate sales | Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	910
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Subsequent Event | Oil and condensate sales | Third Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	920
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Subsequent Event | Oil and condensate sales | Fourth Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	920
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65

Commodity Derivative Financia_7

Commodity Derivative Financial Instruments - Summary of Subsequent Derivative Contracts for Oil and Natural Gas (Details) - Derivatives not designated as hedging instruments - Oil and condensate sales - Swap Contracts - Swap - Subsequent Event MMBTU in Thousands	2 Months Ended
	Feb. 20, 2024 MMBTU $ / MMBTU
First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	300
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	455
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	460
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	460
Derivative contract, weighted average price	3
Derivative contract, price range low	3
Derivative contract, price range high	3
First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	900
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	910
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Third Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	920
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65
Fourth Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	920
Derivative contract, weighted average price	3.65
Derivative contract, price range low	3.65
Derivative contract, price range high	3.65

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 41,983	$ 42,445
Effect of counterparty netting, assets	(3,338)	(10,245)
Net carrying value on balance sheet, assets	38,645	32,200
Gross fair value, liabilities	4,648	13,504
Effect of counterparty netting, liabilities	(3,338)	(10,245)
Net carrying value on balance sheet, liabilities	1,310	3,259
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	(3,338)	(10,245)
Net carrying value on balance sheet, assets	38,645	32,200
Effect of counterparty netting, liabilities	(3,338)	(10,245)
Net carrying value on balance sheet, liabilities	1,310	3,259
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	41,983	42,445
Gross fair value, liabilities	4,648	13,504
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 - Narrati

Significant Customers - Narrative (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Revenue | Customer Concentration Risk | XTO Energy Inc.
Concentration Risk [Line Items]
Total revenue represented by one company	12%	19%

Credit Facility - Narrative (De

Credit Facility - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) lender	Dec. 31, 2022 USD ($)	Oct. 31, 2023 USD ($)	Oct. 30, 2023 USD ($)	Sep. 30, 2023 USD ($)	Apr. 30, 2023 USD ($)
Line Of Credit Facility [Line Items]
Number of lenders | lender	0.667
Credit facility	$ 0	$ 10,000,000
Senior Line of Credit | Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity	$ 1,000,000,000
Right to request a redemption, acquisition of properties in excess of value of borrowing base (percent)	10%
Percentage of hedge positions or property interests sold with a combined value exceeding current borrowing base resulting in base adjustment	5%
Borrowing base			$ 580,000,000			$ 550,000,000
Line of credit facility accordion feature increase limit			$ 375,000,000	$ 375,000,000	$ 400,000,000	$ 375,000,000
Weighted average interest rate (percent)	7.36%	6.92%
Debt instrument, term	90 days
Percentage of availability of lenders' commitments, distributions not permitted	10%
Ratio of total debt to EBITDAX, distributions not permitted	3
Credit facility	$ 0	$ 10,000,000
Unused portion of current borrowing base	$ 375,000,000	$ 365,000,000
Senior Line of Credit | Revolving Credit Facility | Minimum
Line Of Credit Facility [Line Items]
Debt instrument, term	90 days
Current ratio covenant	100%
Senior Line of Credit | Revolving Credit Facility | Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3.5
Senior Line of Credit | Revolving Credit Facility | Prime Rate Plus Margin Rate | Minimum
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.50%	1.50%
Senior Line of Credit | Revolving Credit Facility | Prime Rate Plus Margin Rate | Maximum
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.375%
Senior Line of Credit | Revolving Credit Facility | 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 | Revolving Credit Facility | Secured Overnight Financing Rate (SOFR) | Minimum
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Senior Line of Credit | Revolving Credit Facility | Secured Overnight Financing Rate (SOFR) | Maximum
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.50%	3.50%
Senior Line of Credit | Revolving Credit Facility | Federal Funds Effective Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	0.50%
Senior Line of Credit | Revolving Credit Facility | Adjusted Term Secured Overnight Funds Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1%

Incentive Compensation - Summar

Incentive Compensation - Summary of Information about Restricted Units (Details) - Restricted Common Units - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Units
Unvested, beginning of period (in shares)	823,278
Granted (in shares)	284,772
Vested (in shares)	(400,139)
Forfeited (in shares)	(110,736)
Unvested, end of period (in shares)	597,175	823,278
Weighted-Average Grant-Date Fair Value per Unit
Unvested, beginning of period (in usd per share)	$ 10.72
Granted (in usd per share)	16.03	$ 12	$ 9.25
Vested (in usd per share)	10.40
Forfeited (in usd per share)	11.18
Unvested, end of period (in usd per share)	$ 13.38	$ 10.72

Incentive Compensation - Narrat

Incentive Compensation - Narrative (Details) $ / shares in Units, MMBoe in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2022 MMBoe commonUnit	Dec. 31, 2023 USD ($) commonUnit $ / shares	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 USD ($) $ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash payments of vested units		$ 0	$ 0	$ 0
Restricted Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in usd per share) | $ / shares		$ 16.03	$ 12	$ 9.25
Unrecognized compensation cost		$ 4,300,000
Period of weighted average recognition		1 year 8 months 19 days
Fair value of units vested		$ 6,200,000	$ 4,000,000	$ 2,300,000
Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in usd per share) | $ / shares		$ 14.54	$ 12.40	$ 9.61
Unrecognized compensation cost		$ 4,900,000
Period of weighted average recognition		1 year 7 months 20 days
Fair value of units vested		$ 8,000,000	$ 3,900,000	$ 2,800,000
Award vesting period		3 years
Number of common units | commonUnit		1
Performance Units | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Target number multiplier		0
Performance Units | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Target number multiplier		2
Aspirational Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in usd per share) | $ / shares		$ 16.62
Number of common units | commonUnit	1
Minimum daily oil production | MMBoe	42
Current ratio	1

Incentive Compensation - Summ_2

Incentive Compensation - Summarize Information about Performance Units (Details) - Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Units
Unvested, beginning of period (in shares)	1,175,529
Granted (in shares)	376,832
Vested (in shares)	(520,574)
Forfeited (in shares)	(109,748)
Unvested, end of period (in shares)	922,039	1,175,529
Weighted-Average Grant-Date Fair Value per Unit
Unvested, beginning of period (in usd per share)	$ 10.40
Granted (in usd per share)	14.54	$ 12.40	$ 9.61
Vested (in usd per share)	9.98
Forfeited (in usd per share)	11.20
Unvested, end of period (in usd per share)	$ 12.24	$ 10.40
Additional shares authorized (in shares)	92,060

Incentive Compensation - Summ_3

Incentive Compensation - Summary of Aspirational Performance Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Aspirational Performance Units
Number of Units
Unvested, beginning of period (in shares)	1,412,008
Granted (in shares)	123,308
Vested (in shares)	0
Forfeited (in shares)	(261,803)
Unvested, end of period (in shares)	1,273,513	1,412,008
Weighted-Average Grant-Date Fair Value per Unit
Unvested, beginning of period (in usd per share)	$ 11.58
Granted (in usd per share)	16.62
Vested (in usd per share)	0
Forfeited (in usd per share)	11.63
Unvested, end of period (in usd per share)	$ 12.06	$ 11.58
Performance Cash Award
Weighted-Average Grant-Date Fair Value per Unit
Equity-based compensation expense	$ 5.8
Performance Units
Number of Units
Unvested, beginning of period (in shares)	1,175,529
Granted (in shares)	376,832
Vested (in shares)	(520,574)
Forfeited (in shares)	(109,748)
Unvested, end of period (in shares)	922,039	1,175,529
Weighted-Average Grant-Date Fair Value per Unit
Unvested, beginning of period (in usd per share)	$ 10.40
Granted (in usd per share)	14.54	$ 12.40	$ 9.61
Vested (in usd per share)	9.98
Forfeited (in usd per share)	11.20
Unvested, end of period (in usd per share)	$ 12.24	$ 10.40
Equity-based compensation expense	$ 15.4

Incentive Compensation - Summ_4

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash — short and long-term incentive plan	$ 4,442	$ 7,095	$ 6,824
General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive compensation expense	15,271	24,483	19,042
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	3,852	4,089	4,146
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	4,774	11,174	6,320
Common units | Board of Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive compensation expense	$ 2,203	$ 2,125	$ 1,752

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Details) - 401(k) Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Contribution Plan Disclosure [Line Items]
Maximum tax-deferred contributions	90%
Partnership's defined contributions	$ 0.6	$ 0.6	$ 0.5
Maximum
Defined Contribution Plan Disclosure [Line Items]
Matching employee contributions	5%
After One Year
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	33%
Vesting period	1 year
After Two Years
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	66%
Vesting period	2 years
After Three Years
Defined Contribution Plan Disclosure [Line Items]
Graded vesting percentage	100%
Vesting period	3 years
Service period	3 years

Commitment and Contingencies (D

Commitment and Contingencies (Details)	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Provision for remediation costs	$ 0

Preferred Units - Narrative (De

Preferred Units - Narrative (Details) - Series B Cumulative Convertible Preferred Units $ / shares in Units, $ in Thousands				11 Months Ended	12 Months Ended
	Feb. 26, 2024 USD ($) $ / shares	Nov. 28, 2023	Nov. 28, 2017 USD ($) $ / shares shares	Nov. 28, 2023	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Class of Stock [Line Items]
Shares, price per share (in usd per share) | $ / shares			$ 20.39
Proceeds from issuance of convertible preferred stock			$ 300,000
Preferred units distribution rate (percent)		9.80%		7%
Preferred stock, dividend distribution terms, period of readjustment		2 years
Distribution rate increase if quarterly distributions are accrued and unpaid, percentage		2%		2%
Preferred stock, conversion ratio			1
Minimum underlying value for conversion trigger					$ 10,000
Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2023 and 2022, respectively					299,137	$ 298,361
Accrued distributions					$ 6,000	$ 5,300
Forecast
Class of Stock [Line Items]
Redemption amount	$ 100,000
Preferred Stock, redemption price (in usd per share) | $ / shares	$ 21.41
Redemption price, percentage	105%
Redemption period (in days)	90 days
US Treasury (UST) Interest Rate
Class of Stock [Line Items]
Preferred stock, dividend distribution terms, percent per annum increase		5.50%		5.50%
Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares) | shares			14,711,219

Earnings Per Unit - Computation

Earnings Per Unit - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Net income (loss)	$ 422,549	$ 476,480	$ 181,987
Distributions on Series B cumulative convertible preferred units	(21,776)	(21,000)	(21,000)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	400,773	455,480	160,987
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0
Common units	400,773	455,480	160,987
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	400,773	455,480	160,987
NUMERATOR:
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	400,773	455,480	160,987
Effect of dilutive securities	21,776	21,000	0
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$ 422,549	$ 476,480	$ 160,987
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic) (in shares)	209,970	209,382	208,181
Effect of dilutive securities (in shares)	15,135	15,064	109
Denominator for diluted EPU - weighted average common units outstanding after the effect of dilutive securities (in shares)	225,105	224,446	208,290
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in usd per share)	$ 1.91	$ 2.18	$ 0.77
Per common unit (diluted) (in usd per share)	$ 1.88	$ 2.12	$ 0.77

Earnings Per Unit - Schedule of

Earnings Per Unit - Schedule of Potentially Dilutive Securities excluded from Computation of Earnings Per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Series B cumulative convertible preferred units on an as-converted basis | Common units
Earnings Per Share Basic [Line Items]
Potentially dilutive securities (in shares)	0	0	14,968

Common Units - Narrative (Detai

Common Units - Narrative (Details) - USD ($) $ in Millions		11 Months Ended
	Nov. 28, 2023	Nov. 28, 2023	Dec. 31, 2023	Oct. 30, 2023	Oct. 29, 2023
2023 Unit Repurchase Plan
Class of Stock [Line Items]
Stock authorized for repurchase (in shares)				$ 150
2018 Unit Repurchase Plan
Class of Stock [Line Items]
Stock authorized for repurchase (in shares)					$ 75
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)			15%
Preferred units distribution rate (percent)	9.80%	7%
Preferred stock, dividend distribution terms, period of readjustment	2 years

Common Units - Per share distri

Common Units - Per share distributions to common and subordinated unitholders (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Common units
Class of Stock [Line Items]
Distributions declared and paid (in usd per share)	$ 1.90	$ 1.54	$ 0.85

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details)	Jan. 31, 2024 $ / shares
Common units | Subsequent Event
Subsequent Event [Line Items]
Cash distribution declared (in usd per share)	$ 0.475

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Acquisition Costs of Properties:
Proved	$ 0	$ 0	$ 4,965
Unproved	14,605	149	15,559
Exploration Costs	0	0	1,049
Development Costs	4,601	11,293	3,964
Total	$ 19,206	$ 11,442	$ 25,537

Supplemental Oil and Natural _4

Supplemental Oil and Natural Gas Disclosures - Oil and Natural Gas Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 2,136,056	$ 2,094,563
Unproved properties	890,338	909,344
Total	3,026,394	3,003,907
Accumulated depreciation, depletion, amortization, and impairment	(1,961,899)	(1,916,919)
Oil and natural gas properties, net	$ 1,064,495	$ 1,086,988

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)	12 Months Ended
	Dec. 31, 2023 MMBoe $ / Mcf $ / bbl $ / MMBTU MMcf MMBbls	Dec. 31, 2022 MMBoe $ / bbl $ / Mcf $ / MMBTU MMBbls MMcf	Dec. 31, 2021 MMBoe $ / Mcf $ / bbl $ / MMBTU MMcf MMBbls
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 | MMBoe	64,115	59,824	55,987
Revisions of previous estimates | MMBoe	(2,754)	2,498	11,240
Purchases of minerals in place | MMBoe			308
Sales of minerals in place | MMBoe			(1,167)
Extensions, discoveries and other additions | MMBoe	17,645	15,347	7,343
Production | MMBoe	(14,532)	(13,554)	(13,886)
Balance at the end of the period | MMBoe	64,474	64,115	59,824
Net proved developed reserves | MMBoe	57,101	58,606	56,481
Net Proved Undeveloped Reserves | MMBoe	7,373	5,509	3,343
Oil and condensate sales
Reserve Quantities [Line Items]
Average sale price (in usd per share) | $ / bbl	78.21	94.14	66.55
Average adjusted sale price | $ / bbl	76.90	92.01	63.17
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 | MMBbls	19,184	19,171	15,952
Revisions of previous estimates | MMBbls	675	1,422	4,817
Purchases of minerals in place | MMBbls			272
Sales of minerals in place | MMBbls			(135)
Extensions, discoveries and other additions | MMBbls	2,989	2,182	1,911
Production | MMBbls	(3,757)	(3,591)	(3,646)
Balance at the End of the period | MMBbls	19,091	19,184	19,171
Net Proved Developed Reserves | MMBbls	19,091	19,184	19,111
Net Proved Undeveloped Reserves | MMBbls	0	0	60
Natural Gas Reserves
Reserve Quantities [Line Items]
Average sale price (in usd per share) | $ / MMBTU	2.64	6.36	3.60
Average adjusted sale price | $ / Mcf	2.63	6.50	3.37
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	269,586	243,917	240,211
Revisions of previous estimates | MMcf	(20,578)	6,455	38,537
Purchases of minerals in place | MMcf			216
Sales of minerals in place | MMcf			(6,194)
Extensions, discoveries and other additions | MMcf	87,935	78,992	32,592
Production | MMcf	(64,647)	(59,778)	(61,445)
Balance at the End of the period | MMcf	272,296	269,586	243,917
Net Proved Developed Reserves | MMcf	228,061	236,529	224,222
Net Proved Undeveloped Reserves | MMcf	44,235	33,057	19,695

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, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 2,184,038	$ 3,518,494	$ 2,033,256
Future production costs	(211,826)	(339,603)	(206,785)
Future development costs	(61,723)	(49,081)	(43,500)
Future income tax expense	(6,259)	(10,535)	(6,322)
Future net cash flows (undiscounted)	1,904,230	3,119,275	1,776,649
Annual discount 10% for estimated timing	(884,720)	(1,454,264)	(804,527)
Standardized measure of discounted future net cash flows	$ 1,019,510	$ 1,665,011	$ 972,122	$ 493,497

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning of year	$ 1,665,011	$ 972,122	$ 493,497
Sales, net of production costs	(420,228)	(692,629)	(428,577)
Net changes in prices and production costs related to future production	(649,695)	773,189	537,659
Extensions, discoveries and improved recovery, net of future production and development costs	295,413	476,342	148,732
Previously estimated development costs incurred during the period	0	854	245
Revisions of estimated future development costs	(4,221)	(1,986)	2,254
Revisions of previous quantity estimates, net of related costs	(78,139)	68,270	210,039
Accretion of discount	167,064	97,553	49,530
Purchases of reserves in place, less related costs	0	0	9,254
Sales of reserves in place	0	0	(1,037)
Changes in timing and other	44,305	(28,704)	(49,474)
Net increase (decrease) in standardized measures	(645,501)	692,889	478,625
Standardized measure, end of year	$ 1,019,510	$ 1,665,011	$ 972,122