BLACK STONE MINERALS, L.P., 10-K filed on 2/24/2026
Annual Report
v3.25.4
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 20, 2026
Jun. 30, 2025
Document Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
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     $ 2,277,701,287
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 2025    
Document Fiscal Period Focus FY    
Entity Central Index Key 0001621434    
Common Units      
Document Information [Line Items]      
Entity Partnership Units Outstanding (in shares)   212,333,793  
Cumulative Convertible Preferred Units      
Document Information [Line Items]      
Entity Partnership Units Outstanding (in shares)   14,711,219  
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Auditor Information [Abstract]  
Auditor Firm ID 34
Auditor Name Deloitte & Touche LLP
Auditor Location Houston, Texas
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
CURRENT ASSETS    
Cash and cash equivalents $ 1,478 $ 2,519
Accrued revenue and accounts receivable 65,572 71,093
Commodity derivative assets, net 18,864 1,824
Prepaid expenses and other current assets 9,722 3,108
TOTAL CURRENT ASSETS 95,636 78,544
PROPERTY AND EQUIPMENT    
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,063,709 and $973,028 at December 31, 2025 and 2024, respectively 3,079,340 3,105,457
Accumulated depreciation, depletion, amortization, and impairment (1,855,332) (1,973,460)
Oil and natural gas properties, net 1,224,008 1,131,997
Other property and equipment, net of accumulated depreciation of $15,768 and $14,511 at December 31, 2025 and 2024, respectively 1,126 2,044
NET PROPERTY AND EQUIPMENT 1,225,134 1,134,041
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS 14,784 6,321
TOTAL ASSETS 1,335,554 1,218,906
CURRENT LIABILITIES    
Accounts payable 2,823 5,946
Accrued liabilities 19,388 17,242
Commodity derivative liabilities, net 0 3,852
Other current liabilities 2,412 3,383
TOTAL CURRENT LIABILITIES 24,623 30,423
LONG-TERM LIABILITIES    
Credit facility 154,000 25,000
Accrued incentive compensation 1,011 1,234
Commodity derivative liabilities, net 0 11,581
Asset retirement obligations 22,716 19,286
Other long-term liabilities 4,748 1,943
TOTAL LIABILITIES 207,098 89,467
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY    
Partners' equity — general partner interest 0 0
TOTAL EQUITY 827,978 828,961
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY 1,335,554 1,218,906
Preferred Units    
MEZZANINE EQUITY    
Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2025 and 2024, respectively 300,478 300,478
Common units    
EQUITY    
Partners' equity — common units, 211,873 and 210,695 units outstanding at December 31, 2025 and 2024, respectively $ 827,978 $ 828,961
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
shares in Thousands, $ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Unproved properties $ 1,063,709 $ 973,028
Accumulated depreciation $ 15,768 $ 14,511
Preferred Units    
Partners' equity, preferred units, outstanding (in shares) 14,711 14,711
Common units    
Partners' equity - units, outstanding (in shares) 211,873 210,695
v3.25.4
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
REVENUE      
Revenue from contracts with customers $ 422,328 $ 439,429 $ 501,099
Gain (loss) on commodity derivative instruments, net 47,591 (5,730) 91,117
TOTAL REVENUE 469,919 433,699 592,216
OPERATING (INCOME) EXPENSE      
Lease operating expense 10,141 9,705 11,386
Production costs and ad valorem taxes 39,024 49,577 56,979
Exploration expense 18,634 2,735 2,148
Depreciation, depletion, and amortization 36,887 45,196 45,683
General and administrative 55,463 52,082 51,455
Accretion of asset retirement obligations 1,374 1,298 1,042
Gain on sale of assets, net 0 0 (73)
TOTAL OPERATING EXPENSE 161,523 160,593 168,620
INCOME FROM OPERATIONS 308,396 273,106 423,596
OTHER INCOME (EXPENSE)      
Interest and investment income 237 1,666 1,867
Interest expense (8,930) (3,109) (2,754)
Other income (expense), net 229 (337) (160)
TOTAL OTHER EXPENSE (8,464) (1,780) (1,047)
NET INCOME 299,932 271,326 422,549
Distributions on Series B cumulative convertible preferred units (29,466) (29,466) (21,776)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS 270,466 241,860 400,773
ALLOCATION OF NET INCOME:      
General partner interest 0 0 0
Common units 270,466 241,860 400,773
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 270,466 $ 241,860 $ 400,773
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:      
Per common unit (basic) (in dollars per share) $ 1.28 $ 1.15 $ 1.91
Per common unit (diluted) (in dollars per share) $ 1.28 $ 1.15 $ 1.88
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:      
Weighted average common units outstanding (basic) (in shares) 211,667 210,684 209,970
Weighted average common units outstanding (diluted) (in shares) 211,729 210,780 225,105
Oil and condensate sales      
REVENUE      
Revenue from contracts with customers $ 209,361 $ 269,061 $ 288,296
Natural gas and natural gas liquids sales      
REVENUE      
Revenue from contracts with customers 191,616 157,907 200,297
Lease bonus and other income      
REVENUE      
Revenue from contracts with customers $ 21,351 $ 12,461 $ 12,506
v3.25.4
CONSOLIDATED STATEMENTS OF EQUITY - USD ($)
shares in Thousands, $ in Thousands
Total
Common units
Partners' equity
Partners' equity
Series B cumulative convertible preferred units
Beginning balance (in shares) at Dec. 31, 2022   209,407    
Beginning balance at Dec. 31, 2022     $ 911,451  
Increase (Decrease) in Stockholders' Equity [Roll Forward]        
Repurchases of common units (in shares)   (358)    
Repurchases of common units     (5,496)  
Restricted units granted, net of forfeitures (in shares)   942    
Equity-based compensation     12,525  
Distributions to common unitholders     (398,824)  
Charges to partners' equity for accrued distribution equivalent rights     (2,221)  
Distributions on Series B cumulative convertible preferred units       $ (21,776)
Net income $ 422,549   422,549  
Ending balance (in shares) at Dec. 31, 2023   209,991    
Ending balance at Dec. 31, 2023     918,208  
Increase (Decrease) in Stockholders' Equity [Roll Forward]        
Repurchases of common units (in shares)   (291)    
Repurchases of common units     (4,449)  
Issuance of common units for acquisition of oil and natural gas properties (in shares)   64    
Issuance of common units for acquisition of oil and natural gas properties     1,039  
Restricted units granted, net of forfeitures (in shares)   931    
Equity-based compensation     10,441  
Distributions to common unitholders     (336,931)  
Charges to partners' equity for accrued distribution equivalent rights     (1,207)  
Distributions on Series B cumulative convertible preferred units       (29,466)
Net income 271,326   271,326  
Ending balance (in shares) at Dec. 31, 2024   210,695    
Ending balance at Dec. 31, 2024 828,961   828,961  
Increase (Decrease) in Stockholders' Equity [Roll Forward]        
Repurchases of common units (in shares)   (259)    
Repurchases of common units     (3,777)  
Issuance of common units for acquisition of oil and natural gas properties (in shares)   509    
Issuance of common units for acquisition of oil and natural gas properties     7,417  
Restricted units granted, net of forfeitures (in shares)   928    
Equity-based compensation     11,540  
Distributions to common unitholders     (285,654)  
Charges to partners' equity for accrued distribution equivalent rights     (975)  
Distributions on Series B cumulative convertible preferred units       $ (29,466)
Net income 299,932   299,932  
Ending balance (in shares) at Dec. 31, 2025   211,873    
Ending balance at Dec. 31, 2025 $ 827,978   $ 827,978  
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 299,932 $ 271,326 $ 422,549
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation, depletion, and amortization 36,887 45,196 45,683
Accretion of asset retirement obligations 1,374 1,298 1,042
Amortization of deferred charges 1,085 1,079 1,039
(Gain) loss on commodity derivative instruments (47,591) 5,730 (91,117)
Net cash (paid) received on settlement of commodity derivative instruments 10,989 45,214 82,723
Equity-based compensation 9,620 8,564 10,829
Gain on sale of assets, net 0 0 (73)
Changes in operating assets and liabilities:      
Accrued revenue and accounts receivable 5,545 11,244 53,053
Prepaid expenses and other current assets (6,614) (789) (414)
Accounts payable, accrued liabilities, and other (286) 1,042 (3,827)
Settlement of asset retirement obligations (774) (861) (236)
NET CASH PROVIDED BY OPERATING ACTIVITIES 310,167 389,043 521,251
CASH FLOWS FROM INVESTING ACTIVITIES      
Acquisitions of oil and natural gas properties (107,052) (109,393) (14,605)
Additions to oil and natural gas properties (640) (790) (4,213)
Additions to oil and natural gas properties leasehold costs (11,118) (3,423) (545)
Purchases of other property and equipment (298) (1,425) (450)
Proceeds from the sale of oil and natural gas properties 834 2,795 73
NET CASH USED IN INVESTING ACTIVITIES (118,274) (112,236) (19,740)
CASH FLOWS FROM FINANCING ACTIVITIES      
Borrowings under credit facility 373,000 97,000 64,000
Repayments under credit facility (244,000) (72,000) (74,000)
Debt issuance costs and other (3,037) (64) (216)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (192,934) (344,570) (435,536)
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,041) (67,763) 65,975
Cash and cash equivalents — beginning of the year 2,519 70,282 4,307
Cash and cash equivalents — end of the year 1,478 2,519 70,282
SUPPLEMENTAL DISCLOSURE      
Interest paid 7,383 1,961 1,736
Common units issued for property acquisitions 7,417 1,039 0
Common Units      
CASH FLOWS FROM FINANCING ACTIVITIES      
Distributions to unitholders (285,654) (336,931) (398,824)
Repurchases of common units (3,777) (4,449) (5,496)
Preferred Units      
CASH FLOWS FROM FINANCING ACTIVITIES      
Distributions to unitholders $ (29,466) $ (28,126) $ (21,000)
v3.25.4
CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Distributions to common unitholders (in dollars per share) $ 1.35 $ 1.60 $ 1.90
Series B cumulative convertible preferred units on an as-converted basis      
Distributions on Series B cumulative convertible preferred units (in dollars per share) $ 2.00 $ 2.00 $ 1.48
v3.25.4
BUSINESS AND BASIS OF PRESENTATION
 12 Months Ended
Dec. 31, 2025
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 consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting
The Partnership operates in a single reportable segment, which consists of a single operating segment. The Partnership generates revenue from the sale of oil and natural gas, as well as lease bonus and other income that is derived from our oil and natural gas properties. These properties are all located within the continental U.S., including all of the major onshore producing basins. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker ("CODM") in deciding how to allocate resources and assess performance. The Partnership’s co-chief executive officers, collectively, have been determined to be the CODM and allocates resources and assesses performance based upon net income reported on the consolidated statements of operations. The significant segment expenses regularly provided to the CODM include lease operating expense, production costs and ad valorem taxes, exploration expense, depletion, depreciation, and amortization, general and administrative expense, and interest expense. Other segment items include accretion of asset retirement obligations, gain on sale of assets, net, interest and investment income, and other income (expense), net. These significant expenses and other segment items are the same as the line items presented in the consolidated statements of operations. The CODM is not regularly provided with additional expense information beyond what is presented in the consolidated statements of operations. The measure of segment assets is reported on the consolidated balance sheets as total assets. The CODM uses net income to evaluate the income generated from segment assets in deciding whether to reinvest profits into the Partnership's oil and natural gas properties or for other activities such as distributions to unitholders and reducing outstanding borrowings as applicable.
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 12 Months Ended
Dec. 31, 2025
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 proved oil and natural gas properties, if necessary. 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 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.
Accrued Revenue and Accounts Receivable
The Partnership’s accrued revenue and accounts receivable balance results primarily from operators’ sales of oil and natural gas to purchasers. Accrued revenue and accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of operators 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 accrued revenue and accounts receivable:
December 31,
20252024
(in thousands)
Accrued revenue$62,679 $67,047 
Accounts receivable2,893 4,046 
Total accrued revenue and accounts receivable$65,572 $71,093 
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 gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership 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. Realized and unrealized gains on commodity derivative instruments are recorded within cash flows from operating activities in the accompanying consolidated statements of cash flows.
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 operator base is high and has not experienced significant write-offs in its accounts receivable balances. See "Note 7 – Significant Operators" 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.
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 proved 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 $35.7 million, $44.8 million, and $45.0 million for the years ended December 31, 2025, 2024, and 2023, 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. 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 or loss. 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 $1.2 million, $0.4 million, and $0.7 million for the years ended December 31, 2025, 2024, and 2023, 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,
 20252024
 (in thousands)
Accrued liabilities:
Accrued incentive compensation$7,824 $8,356 
Accrued general and administrative847 954 
Accrued property taxes6,029 6,498 
Accrued lease operating expenses1,985 713 
Accrued seismic costs1,500 — 
Accrued other1,203 721 
Total accrued liabilities$19,388 $17,242 

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 $1.1 million, $1.1 million, and $1.0 million for the years ended December 31, 2025, 2024, and 2023, 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, 2025 and 2024, 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.
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 Accrued revenue and 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.
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.
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, and accounts payable approximate their fair value at December 31, 2025 and 2024 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 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures, which enhances the disclosures required for certain expense captions in the Partnership's annual and interim consolidated financial statements. The guidance is effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on its disclosures.
v3.25.4
ASSET RETIREMENT OBLIGATIONS
 12 Months Ended
Dec. 31, 2025
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 current portion of our ARO is included in the line item Other current liabilities on the consolidated balance sheet, while the noncurrent portion is separately presented as Asset retirement obligations within long-term liabilities. 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,
 20252024
 (in thousands)
Beginning asset retirement obligations$21,318 $20,267 
Liabilities incurred30 46 
Liabilities settled(774)(713)
Accretion expense1,374 1,298 
Revisions in estimated costs2,330 953 
Dispositions(13)(533)
Ending asset retirement obligations$24,265 $21,318 
Current asset retirement obligations$1,549 $2,032 
Noncurrent asset retirement obligations$22,716 $19,286 
v3.25.4
OIL AND NATURAL GAS PROPERTIES
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
OIL AND NATURAL GAS PROPERTIES OIL AND NATURAL GAS PROPERTIES
Acquisitions
During the year ended December 31, 2025, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $114.5 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $107.1 million in cash that was funded from operating activities and $7.4 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.
During the year ended December 31, 2024, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs, and were considered asset acquisitions. The cash portion of the consideration paid of $109.4 million was funded with our borrowings under our Credit Facility and funds from operating activities, and $1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.
During 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 East Texas.
Asset Exchange
The Partnership completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas. These transactions, which are described below, involved partial dispositions of unproved property, and no gains or losses were recognized.
In March 2025, the Partnership closed on a transaction with a third-party operator whereby the Partnership acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.
In February 2025, the Partnership closed on a transaction with a third-party operator whereby the Partnership exchanged oil and natural gas leases covering certain acreage in East Texas. The Partnership acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres.
In July 2024, the Partnership closed on a transaction with a third-party operator whereby the Partnership acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.
Farmout Agreements
The Partnership previously entered into farmout arrangements covering all its non-operated working interests under its Joint Exploration Agreements ("JEAs"; each, a "JEA") with Aethon in San Augustine and Angelina Counties. In May 2025, the farmout agreements covering the interests under the JEAs with Aethon terminated, and Aethon assumed the associated working interests as part of an amendment to the Partnership's JEAs with Aethon. In June 2025, the Partnership entered into a farmout arrangement covering all its non-operated working interests under its JEA with Revenant Energy in Angelina, Nacogdoches, and San Augustine Counties, under which the Partnership farmed out its undivided 35% working interest to an external capital provider.
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 (a "triggering event"). When assessing producing properties for impairment, if a triggering event has been identified, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. For the years ended December 31, 2025, 2024, and 2023, the Partnership did not identify any indicators of impairment and as such, no impairment of oil and natural gas properties were recognized. See "Note 6 - Fair Value Measurements" for additional information.
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
 12 Months Ended
Dec. 31, 2025
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, 2025 and 2024, 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 statements 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, 2025 and 2024. 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, 2025, the Partnership had eight counterparties, all of which 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, 2025
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
  (in thousands)
Assets:    
       Current assetCommodity derivative assets, net$24,930 $(6,066)$18,864 
       Long-term assetDeferred charges and other long-term assets4,325 (196)4,129 
          Total assets $29,255 $(6,262)$22,993 
Liabilities:    
       Current liabilityCommodity derivative liabilities, net$6,066 $(6,066)$— 
       Long-term liabilityCommodity derivative liabilities, net196 (196)— 
         Total liabilities $6,262 $(6,262)$— 
  
As of December 31, 2024
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
  (in thousands)
Assets:    
       Current assetCommodity derivative assets, net$4,866 $(3,042)$1,824 
       Long-term assetDeferred charges and other long-term assets768 (768)— 
          Total assets $5,634 $(3,810)$1,824 
Liabilities:    
       Current liabilityCommodity derivative liabilities, net$6,894 $(3,042)$3,852 
       Long-term liabilityCommodity derivative liabilities, net12,349 (768)11,581 
          Total liabilities $19,243 $(3,810)$15,433 
Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities), as well as net cash paid or received on settlements, are presented on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments, net and consist of the following for the periods presented:
 For the year ended December 31,
Derivatives not designated as hedging instruments202520242023
 (in thousands)
Beginning fair value of commodity derivative instruments$(13,609)$37,335 $28,941 
Gain (loss) on oil derivative instruments30,029 (6,591)3,888 
Gain (loss) on natural gas derivative instruments17,562 861 87,229 
Net cash paid (received) on settlements of oil derivative instruments(12,102)8,524 (2,653)
Net cash paid (received) on settlements of natural gas derivative instruments1,113 (53,738)(80,070)
Net change in fair value of commodity derivative instruments36,602 (50,944)8,394 
Ending fair value of commodity derivative instruments$22,993 $(13,609)$37,335 
The Partnership had the following open derivative contracts for oil as of December 31, 2025:
 Volume (MBbl)Weighted Average Price (per Bbl)Range (per Bbl)
Period and Type of ContractLowHigh
Oil Swap Contracts:    
2025
Fourth quarter185 $71.22 $70.02 $73.15 
2026    
First quarter615 64.39 62.00 67.35 
Second quarter615 64.39 62.00 67.35 
Third quarter615 64.39 62.00 67.35 
Fourth quarter615 64.39 62.00 67.35 
2027
First quarter180 59.56 58.85 60.10 
Second quarter180 59.56 58.85 60.10 
Third quarter180 59.56 58.85 60.10 
Fourth quarter180 59.56 58.85 60.10 

The Partnership had the following open derivative contracts for natural gas as of December 31, 2025:
 Volume (BBtu)Weighted Average Price (per MMBtu)Range (per MMBtu)
Period and Type of ContractLowHigh
Natural Gas Swap Contracts:    
2026
First quarter12,600 $3.73 $3.50 $4.46 
Second quarter12,740 3.73 3.50 4.46 
Third quarter12,880 3.73 3.50 4.46 
Fourth quarter12,880 3.73 3.50 4.46 
2027
First quarter6,300 $3.93 $3.85 $4.00 
Second quarter6,370 3.93 3.85 4.00 
Third quarter6,440 3.93 3.85 4.00 
Fourth quarter6,440 3.93 3.85 4.00 

The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2025:
 Volume (MBbl)Weighted Average Price (per MMBtu)Range (per MMBtu)
Period and Type of ContractLowHigh
Oil Swap Contracts:    
2027
First quarter150 $59.74 $58.13 $61.20 
Second quarter150 59.74 58.13 61.20 
Third quarter150 59.74 58.13 61.20 
Fourth quarter150 59.74 58.13 61.20 
v3.25.4
FAIR VALUE MEASUREMENTS
 12 Months Ended
Dec. 31, 2025
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 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, 2025 and 2024.
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, 2025 and 2024 approximated the fair value due to variable market rates of interest.
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 UsingEffect of  
 Level 1Level 2Level 3Counterparty NettingTotal
 (in thousands)
As of December 31, 2025     
Financial Assets     
Commodity derivative instruments$— $29,255 $— $(6,262)$22,993 
Financial Liabilities     
Commodity derivative instruments— 6,262 — (6,262)— 
As of December 31, 2024     
Financial Assets     
Commodity derivative instruments$— $5,634 $— $(3,810)$1,824 
Financial Liabilities     
Commodity derivative instruments— 19,243 — (3,810)15,433 
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 when impaired.
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 had no business combinations for the years ended December 31, 2025 and 2024. See "Note 4 — Oil and Natural Gas Properties." 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 impaired. 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 future cash flows associated with those properties include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and, with respect to estimating fair value, 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 are 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, 2025 and 2024. There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended December 31, 2025 and 2024.
v3.25.4
SIGNIFICANT OPERATORS
 12 Months Ended
Dec. 31, 2025
Risks and Uncertainties [Abstract]  
SIGNIFICANT OPERATORS SIGNIFICANT OPERATORS
The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. For the year ended December 31, 2025, Aethon represented approximately 14% of total oil and natural gas revenues. For the year ended December 31, 2024, Pioneer Natural Resources and XTO Energy, subsidiaries of ExxonMobil Corporation, collectively represented 13% of total oil and natural gas revenues. No single operator exceeded 10% of total oil and natural gas revenues for the year ended December 31, 2023.
If the Partnership lost a significant operator on its properties, such loss could impact revenue derived from its mineral and royalty interests and working interests. The loss of any single operator is mitigated by the Partnership’s diversified operator base.
v3.25.4
CREDIT FACILITY
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
CREDIT FACILITY CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2030. 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. The borrowing base was reaffirmed in April 2024, November 2024 and April 2025 at $580.0 million. After each redetermination the Partnership elected to maintain cash commitments at $375.0 million. In October 2025, the Partnership amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and reduce the adjustment applied to secured overnight financing rate ("SOFR") loans. Concurrent with the Credit Facility amendment, the borrowing base was reaffirmed at $580.0 million and the Partnership elected to maintain cash commitments at $375.0 million. All existing banks in the lender syndicate elected to continue participating in the Credit Facility. No other significant terms were changed as part of the amendment. The next semi-annual redetermination is scheduled for April 2026.
The Partnership’s borrowings under the Credit Facility bear interest at a floating rate determined by the type of loan the Partnership has elected to take: a SOFR loan or a base-rate loan. Both types of loans bear interest at a reference rate plus a margin that varies with the amount of borrowings outstanding under the Credit Facility. The reference rate for SOFR loans is equal to SOFR as published by the Federal Reserve Bank of New York, adjusted for the borrowing term, plus 2.50%, which is referred to as Adjusted Term SOFR. Effective October 31, 2025, Adjusted Term SOFR was amended to remove the additional 0.10% "adjustment" to the underlying SOFR reference rate. The reference rate for base rate loans is the highest of (a) Wells Fargo’s prime commercial lending rate for that day, (b) the Federal Funds Rate in effect on that day plus 0.50%, and (c) Adjusted Term SOFR for a one month-tenor plus 1.00%. As of December 31, 2024 and December 31, 2025, the applicable margin for the base rate loans ranged from 1.50% to 2.50%, and the margin for SOFR loans ranged from 2.50% to 3.50%.
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 7.03% during the year ended December 31, 2025 and the weighted-average interest rate was 7.50% during the year ended December 31, 2024. 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 Facility (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, 2025, the Partnership was in compliance with all financial covenants in the Credit Facility.
The aggregate principal balance outstanding was $154.0 million and $25.0 million at December 31, 2025 and 2024, respectively. The unused portion of the available borrowings under the Credit Facility was $221.0 million and $350.0 million at December 31, 2025 and 2024, respectively.
v3.25.4
INCENTIVE COMPENSATION
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
INCENTIVE COMPENSATION INCENTIVE COMPENSATION
Overview
The board of directors of the Partnership’s general partner (the "Board") previously 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 were eligible to receive awards with respect to the Partnership’s common units. The 2015 LTIP provided for 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 granted under the 2015 LTIP were based on a predetermined schedule as approved by the Board or a committee thereof.
In 2025, the Board approved the adoption of a new long-term incentive plan to replace the 2015 LTIP following its expiration, which allows for the grant of the same type of awards and to the same service providers as was provided for under the 2015 LTIP. On June 12, 2025, our unitholders approved the Board’s adoption of the Black Stone Minerals, L.P. 2025 Long Term Incentive Plan (the “2025 LTIP”) at the Partnership’s 2025 Annual Meeting. Following the unitholder approval of the 2025 LTIP, no further awards will be granted under the 2015 LTIP. which expired on May 6, 2025, but which will continue to govern awards previously granted and still outstanding as of such expiration date.
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 of the Board (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 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 2025 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2028. In January of each year, non-employee directors of the Partnership’s general partner receive compensation under the 2025 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, 2025.
Number of UnitsWeighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2024527,743 $15.48 
Granted392,928 15.11 
Vested(286,820)14.78 
Forfeited(95,971)15.58 
Unvested at December 31, 2025537,880 $15.57 
The weighted-average grant-date fair value per unit for unit-based awards was $15.11, $16.39, and $16.03 for the years ended December 31, 2025, 2024, and 2023, respectively. As of December 31, 2025, unrecognized compensation cost associated with restricted unit awards was $4.6 million, which the Partnership expects to recognize over a weighted-average period of 1.74 years. The fair value of units vested for the years ended December 31, 2025, 2024, and 2023 was $4.1 million, $5.0 million, and $6.2 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2025, 2024, and 2023.
Performance Unit Awards

The Compensation Committee also approves grants of restricted performance units that are subject to both performance-based and service-based vesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Partnership’s performance
over each of the three calendar year performance periods commencing January 1 of the first calendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metrics are achieved. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate of performance metrics by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award. Distribution equivalent rights for the restricted performance unit awards are charged to partners’ capital.
The following table summarizes information about performance units for the year ended December 31, 2025.  
Performance unitsNumber of Units
Weighted-Average Grant-Date
Fair Value per Unit
Unvested at December 31, 2024800,162 $14.71 
Granted1
393,443 15.10 
Vested(354,158)12.78 
Forfeited(96,595)15.57 
Unvested at December 31, 2025742,852 $15.73 
1  Includes 515 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 $15.10, $15.11, and $14.54 for the years ended December 31, 2025, 2024, and 2023, respectively. Unrecognized compensation cost associated with performance unit awards was $3.7 million as of December 31, 2025, which the Partnership expects to recognize over a weighted-average period of 1.90 years. The fair value of performance units vested for the years ended December 31, 2025, 2024 and 2023 was $5.2 million, $6.3 million, and $8.0 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 included performance cash awards and performance equity awards in the form of restricted performance units. The awards were contingent on achieving a production target of at least 42 Mboe per day of average daily royalty production in the fourth quarter or December 2025. As the production target was not met, all awards were forfeited, and no compensation expense was recognized for the year ended December 31, 2025.
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, 2025, 2024, and 2023.
 Year Ended December 31,
Incentive compensation expense202520242023
 (in thousands)
Cash — short and long-term incentive plan$5,053 $4,940 $4,442 
Equity-based compensation — restricted common units4,210 3,982 3,852 
Equity-based compensation — restricted performance units3,247 2,284 4,774 
Board of Directors incentive plan2,163 2,298 2,203 
Total incentive compensation expense$14,673 $13,504 $15,271 
v3.25.4
EMPLOYEE BENEFIT PLANS
 12 Months Ended
Dec. 31, 2025
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 $0.8 million, $0.7 million, and $0.6 million for the years ended December 31, 2025, 2024, and 2023, respectively.
v3.25.4
COMMITMENTS AND CONTINGENCIES
 12 Months Ended
Dec. 31, 2025
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 material to the consolidated financial statements, and no provision for potential remediation costs has been recorded.
Litigation
From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of December 31, 2025 will be resolved without material adverse effect on the Partnership’s financial condition or operations.
v3.25.4
PREFERRED UNITS
 12 Months Ended
Dec. 31, 2025
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 for a cash purchase price of $20.39 per Series B cumulative convertible preferred unit, resulting in total proceeds of $300.0 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”). The Distribution Rate adjusted on November 28, 2023 and will be readjusted 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 Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025. 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 have a stated liquidation preference of $21.41 per unit, or $315.0 million in the aggregate, plus any accrued and unpaid distributions, or if greater, the amount such units would be entitled to if converted into common units.
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 during biennial 90-day windows. On August 21, 2025, the Partnership entered into an agreement with the holders of its Series B cumulative convertible preferred units. Under the agreement, the Partnership agreed not to exercise its redemption option, and the holders agreed to vote their preferred units in accordance with the recommendations of the Partnership’s Board of Directors on ordinary course matters and to certain customary transfer and standstill restrictions. These provisions remain in effect through November 27, 2027, with the next redemption window opening on November 28, 2027.
The Partnership must provide 20 business days' notice to the holders of the Series B cumulative convertible preferred units of its intent to redeem, and the holders may either allow the redemption to occur or elect to convert the Series B cumulative convertible preferred units into common units as described above.
The Series B cumulative convertible preferred units had a carrying value of $300.5 million, including accrued distributions of $7.4 million, as of December 31, 2025 and 2024.
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.
v3.25.4
EARNINGS PER UNIT
 12 Months Ended
Dec. 31, 2025
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,
 202520242023
 (in thousands, except per unit amounts)
NET INCOME$299,932 $271,326 $422,549 
Distributions on Series B cumulative convertible preferred units (29,466)(29,466)(21,776)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS$270,466 $241,860 $400,773 
ALLOCATION OF NET INCOME:   
General partner interest$— $— $— 
Common units270,466 241,860 400,773 
 $270,466 $241,860 $400,773 
NUMERATOR:
Numerator for basic EPU - net income attributable to common unitholders$270,466 $241,860 $400,773 
Effect of dilutive securities— — 21,776 
Numerator for diluted EPU - net income attributable to common unitholders after the effect of dilutive securities$270,466 $241,860 $422,549 
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)211,667 210,684 209,970 
Effect of dilutive securities
62 96 15,135 
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities211,729 210,780 225,105 
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:   
Per common unit (basic)$1.28 $1.15 $1.91 
Per common unit (diluted)$1.28 $1.15 $1.88 
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,
202520242023
(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis15,072 15,072 — 
v3.25.4
COMMON UNITS
 12 Months Ended
Dec. 31, 2025
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, then adjusting on November 28, 2023 and readjusting every two years thereafter, to a rate equal to the greater of (i) the rate in effect immediately prior to the relevant readjustment and (ii) the 10-year Treasury Rate as of such readjustment date plus 5.5% per annum (which rate adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025 and
•second, to the holders of common units.
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, 2025. The program is funded from the Partnership’s cash on hand or through borrowings under the Credit Facility. Any repurchased units are canceled.
v3.25.4
SUBSEQUENT EVENTS
 12 Months Ended
Dec. 31, 2025
Subsequent Events [Abstract]  
SUBSEQUENT EVENTS SUBSEQUENT EVENTS
Distribution
On February 5, 2026, the Board approved a distribution for the period from October 1, 2025 to December 31, 2025 of $0.300 per common unit. Distributions will be paid on February 25, 2026 to unitholders of record at the close of business on February 18, 2026.
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED
 12 Months Ended
Dec. 31, 2025
Oil and Gas Disclosure [Abstract]  
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—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,
 202520242023
 (in thousands)
Acquisition Costs of Properties1:
   
Proved$346 $2,894 $— 
Unproved114,122 107,537 14,605 
Development Costs1
11,757 4,208 4,601 
Total$126,225 $114,639 $19,206 
 
1 Unproved properties include purchases of leasehold prospects.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment.
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below:
 As of December 31,
 20252024
 (in thousands)
Proved properties$2,015,631 $2,132,429 
Unproved properties1,063,709 973,028 
Total3,079,340 3,105,457 
Accumulated depreciation, depletion, amortization, and impairment(1,855,332)(1,973,460)
Oil and natural gas properties, net$1,224,008 $1,131,997 
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 $66.01, $76.32, and $78.21 per barrel as of December 31, 2025, 2024, and 2023, 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 $3.39, $2.13, and $2.64 per MMBtu as of December 31, 2025, 2024, and 2023, 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 $63.40 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2025, $74.14 per barrel for oil and $2.22 per Mcf for natural gas as of December 31, 2024, and $76.90 per barrel for oil and $2.63 per Mcf for natural gas as of December 31, 2023.
 Crude Oil (MBbl)Natural Gas (MMcf)Total (MBoe)
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 additions2
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 
Revisions of previous estimates1
119 (25,218)(4,084)
Purchases of minerals in place3
10 314 62 
Sales of minerals in place4
(163)(1,250)(371)
Extensions, discoveries and other additions2
2,015 56,323 11,402 
Production(3,606)(62,984)(14,103)
Net proved reserves at December 31, 2024
17,466 239,481 57,380 
Revisions of previous estimates1
669 (2,732)214 
Purchases of minerals in place3
70 943 227 
Sales of minerals in place4
(24)(75)(37)
Extensions, discoveries and other additions2
1,714 47,877 9,693 
Production(3,259)(56,237)(12,632)
Net proved reserves at December 31, 2025
16,636 229,257 54,845 
Net Proved Developed Reserves   
December 31, 202319,091 228,061 57,101 
December 31, 202417,466 220,901 54,283 
December 31, 202516,241 191,632 48,179 
Net Proved Undeveloped Reserves   
December 31, 2023— 44,235 7,373 
December 31, 2024— 18,580 3,097 
December 31, 2025395 37,625 6,666 
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 extensions and additions related to drilling activities in multiple areas, primarily within the Haynesville/Bossier play trend and the Permian Basin.
3 Includes the acquisition of mineral and royalty reserves primarily within the Haynesville/Bossier play trend.
4 Includes divestitures of working interest reserves primarily within the Austin Chalk play trend.
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 federal income taxes deducted in the calculation of the standardized measure because the Partnership is not subject to them. Future income tax expense includes applicable state taxes. See "Note 2 – Summary of Significant Accounting Policies" for additional information.
 Year Ended December 31,
 202520242023
 (in thousands)
Future cash inflows$1,828,128 $1,827,316 $2,184,038 
Future production costs(178,506)(164,886)(211,826)
Future development costs(63,833)(62,137)(61,723)
Future income tax expense(5,753)(5,433)(6,259)
Future net cash flows (undiscounted)1,580,036 1,594,860 1,904,230 
Annual discount 10% for estimated timing
(690,837)(726,773)(884,720)
Total$889,199 $868,087 $1,019,510 

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
 Year Ended December 31,
 202520242023
 (in thousands)
Standardized measure, beginning of year$868,087 $1,019,510 $1,665,011 
Sales, net of production costs(351,813)(367,686)(420,228)
Net changes in prices and production costs related to future production44,268 (51,740)(649,695)
Extensions, discoveries and improved recovery, net of future production and development costs179,769 174,145 295,413 
Previously estimated development costs incurred during the period— — — 
Revisions of estimated future development costs(551)(123)(4,221)
Revisions of previous quantity estimates, net of related costs4,526 (65,903)(78,139)
Accretion of discount87,104 102,292 167,064 
Purchases of reserves in place, less related costs3,700 572 — 
Sales of reserves in place(795)(5,194)— 
Changes in timing and other54,904 62,214 44,305 
Net increase (decrease) in standardized measures21,112 (151,423)(645,501)
Standardized measure, end of year$889,199 $868,087 $1,019,510 
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.
v3.25.4
Insider Trading Arrangements
shares in Thousands
 3 Months Ended
Dec. 31, 2025
shares
Trading Arrangements, by Individual  
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
Steve Putnam [Member]  
Trading Arrangements, by Individual  
Material Terms of Trading Arrangement On December 4, 2025, Steve Putman, our Senior Vice President, General Counsel, and Secretary, adopted a trading arrangement for the sale of common units (a “Rule 10b5-1 Trading arrangement”) that is intended to satisfy the affirmative defense conditions of Securities Exchange Act Rule 10b5-1(c). Mr. Putman’s Rule 10b5-1 Trading Plan provides for the sale of approximately 90,000 common units, subject to adjustment upon future settlement of certain outstanding unit-based awards and associated distribution equivalent rights, pursuant to the terms of the plan and will terminate on the earlier of (i) December 4, 2026, (ii) the first date on which all trades set forth in the plan have been executed or (iii) such date as the plan is otherwise terminated according to its terms
Name Steve Putman
Title Senior Vice President, General Counsel, and Secretary
Rule 10b5-1 Arrangement Adopted true
Adoption Date December 4, 2025
Expiration Date December 4, 2026
Arrangement Duration 365 days
Aggregate Available 90
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
Cybersecurity threats have become significantly more numerous and sophisticated over time, and the oil and gas industry in particular is highly targeted by malicious actors seeking to attack oil and gas infrastructure to disrupt operations. Because we are focused on mineral and royalty interests, we do not maintain any material physical infrastructure; nonetheless, being an industry participant increases our exposure to external attacks. We are committed to safeguarding our information technology systems and data and managing the risks associated with cybersecurity threats and implemented governance structures, processes, and technologies designed to prevent, detect, investigate, and mitigate any incident that could pose a cybersecurity risk.
Our Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team,” which, together with the VP IT, make up the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats. Collectively, the four members of the Cybersecurity Team have over 75 years of cybersecurity-related experience in both the private and public sectors, including perimeter and
internal network security, secure email gateway, B2B and B2C eCommerce, on-premises and cloud storage environment security, and ransomware protection solutions. In addition, members of the Cybersecurity Team have multiple network-security certifications relevant to the technologies we deploy.
Our Board of Directors provides oversight of our enterprise-wide risk management, which includes cybersecurity risk-management, and the Audit Committee assists the Board with oversight of cybersecurity matters. The VP IT reports on cybersecurity matters to senior management on a regular basis and to the Audit Committee at least annually, and more often if needed. The Audit Committee, in turn, makes periodic reports to the Board on relevant cybersecurity matters.
Our VP IT, the Director of our Infrastructure Team, and our General Counsel make up the Information Security Committee, which has the initial responsibility for the assessment of and response to cybersecurity incidents consistent with our formal incident-response plan. Pursuant to the incident-response plan, more serious incidents are escalated to other senior members of management, including the Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, as well as to the Audit Committee and our external auditors, as appropriate.
We maintain the following processes to assess, identify, and manage risks from cybersecurity threats:
•Ongoing Threat Assessment. We maintain multiple threat intelligence subscriptions, and we monitor relevant cybersecurity resources on an ongoing basis to identify and anticipate potential threats to our network infrastructure.
•Layered Security. We use multiple tiers of security as part of our efforts to reduce our exposure to cyberattacks. We leverage and maintain perimeter network defense solutions to discourage network-intrusion attempts. Within our network, we leverage endpoint security and ransomware detection and prevention solutions, and we use continuous monitoring of alerts and activities to identify and respond to any irregularities that could be associated with threats.
•Training and Awareness. We conduct awareness training for our employees as part of our efforts to enable them to identify and report cybersecurity threats. We require cybersecurity training during employee and contractor onboarding, and we seek to reinforce the training through phishing tests on at least a quarterly basis as part of our efforts to reduce the potential for successful phishing and social-engineering attacks.
•Cybersecurity Tool and Processes and Industry Standards. We refer to industry standards, such as those issued by National Institutes of Standards and Technology ("NIST") and International Organization for Standardization ("ISO"), as part of our efforts to maintain best practices across our environment and we use various cybersecurity tools and processes designed to manage cybersecurity threats including network and systems authentication, network and infrastructure architecture security, endpoint security, and operating system patching.
•Third-Party Network Security Assessments. We engage a third-party consultant to conduct external penetration testing at least annually. Our cybersecurity processes are adjusted as needed based on the results of these assessments. The assessment results are reported to the Audit Committee and Board, and our external auditor reviews our cybersecurity solutions and posture on at least an annual basis.
•Third-Party Risk Management. We conduct information-security assessments before allowing sensitive data to be hosted by third parties. We also ensure SOC-1 or SOC-2 compliance for our third party providers, including our banking, payroll, and stock-plan administration relationships.
While we and our service providers have experienced cybersecurity incidents in the past, as of the date of this Annual Report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us, including our business strategy, results of operation, or financial condition. For more information regarding the risks we face, please read Part I, Item 1A. “Risk Factors—General Risk Factors—Various security risks, including cybersecurity threats, data breaches, and other disruptions, could significantly affect us.”
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] Cybersecurity threats have become significantly more numerous and sophisticated over time, and the oil and gas industry in particular is highly targeted by malicious actors seeking to attack oil and gas infrastructure to disrupt operations. Because we are focused on mineral and royalty interests, we do not maintain any material physical infrastructure; nonetheless, being an industry participant increases our exposure to external attacks. We are committed to safeguarding our information technology systems and data and managing the risks associated with cybersecurity threats and implemented governance structures, processes, and technologies designed to prevent, detect, investigate, and mitigate any incident that could pose a cybersecurity risk.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
Our Board of Directors provides oversight of our enterprise-wide risk management, which includes cybersecurity risk-management, and the Audit Committee assists the Board with oversight of cybersecurity matters. The VP IT reports on cybersecurity matters to senior management on a regular basis and to the Audit Committee at least annually, and more often if needed. The Audit Committee, in turn, makes periodic reports to the Board on relevant cybersecurity matters.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team,” which, together with the VP IT, make up the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]
Our VP IT, the Director of our Infrastructure Team, and our General Counsel make up the Information Security Committee, which has the initial responsibility for the assessment of and response to cybersecurity incidents consistent with our formal incident-response plan. Pursuant to the incident-response plan, more serious incidents are escalated to other senior members of management, including the Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, as well as to the Audit Committee and our external auditors, as appropriate.
Cybersecurity Risk Role of Management [Text Block]
Our VP IT, the Director of our Infrastructure Team, and our General Counsel make up the Information Security Committee, which has the initial responsibility for the assessment of and response to cybersecurity incidents consistent with our formal incident-response plan. Pursuant to the incident-response plan, more serious incidents are escalated to other senior members of management, including the Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, as well as to the Audit Committee and our external auditors, as appropriate.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block] Our Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team,” which, together with the VP IT, make up the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Collectively, the four members of the Cybersecurity Team have over 75 years of cybersecurity-related experience in both the private and public sectors, including perimeter and internal network security, secure email gateway, B2B and B2C eCommerce, on-premises and cloud storage environment security, and ransomware protection solutions. In addition, members of the Cybersecurity Team have multiple network-security certifications relevant to the technologies we deploy.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]
Our Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team,” which, together with the VP IT, make up the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats. Collectively, the four members of the Cybersecurity Team have over 75 years of cybersecurity-related experience in both the private and public sectors, including perimeter and
internal network security, secure email gateway, B2B and B2C eCommerce, on-premises and cloud storage environment security, and ransomware protection solutions. In addition, members of the Cybersecurity Team have multiple network-security certifications relevant to the technologies we deploy.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Basis of Presentation
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 consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting
Segment Reporting
The Partnership operates in a single reportable segment, which consists of a single operating segment. The Partnership generates revenue from the sale of oil and natural gas, as well as lease bonus and other income that is derived from our oil and natural gas properties. These properties are all located within the continental U.S., including all of the major onshore producing basins. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker ("CODM") in deciding how to allocate resources and assess performance. The Partnership’s co-chief executive officers, collectively, have been determined to be the CODM and allocates resources and assesses performance based upon net income reported on the consolidated statements of operations. The significant segment expenses regularly provided to the CODM include lease operating expense, production costs and ad valorem taxes, exploration expense, depletion, depreciation, and amortization, general and administrative expense, and interest expense. Other segment items include accretion of asset retirement obligations, gain on sale of assets, net, interest and investment income, and other income (expense), net. These significant expenses and other segment items are the same as the line items presented in the consolidated statements of operations. The CODM is not regularly provided with additional expense information beyond what is presented in the consolidated statements of operations. The measure of segment assets is reported on the consolidated balance sheets as total assets. The CODM uses net income to evaluate the income generated from segment assets in deciding whether to reinvest profits into the Partnership's oil and natural gas properties or for other activities such as distributions to unitholders and reducing outstanding borrowings as applicable.
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 proved oil and natural gas properties, if necessary. 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 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.
Accrued Revenue and Accounts Receivable
Accrued Revenue and Accounts Receivable
The Partnership’s accrued revenue and accounts receivable balance results primarily from operators’ sales of oil and natural gas to purchasers. Accrued revenue and accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of operators 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 inherent commodity price risk associated with its operations, the Partnership uses oil and gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership 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. Realized and unrealized gains on commodity derivative instruments are recorded within cash flows from operating activities in the accompanying consolidated statements of cash flows.
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 operator base is high and has not experienced significant write-offs in its accounts receivable balances. See "Note 7 – Significant Operators" 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
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.
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 proved 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 $35.7 million, $44.8 million, and $45.0 million for the years ended December 31, 2025, 2024, and 2023, 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. 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 or loss. 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
Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from 3 years to 7 years.
Repairs and Maintenance
Repairs and Maintenance
The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.
Debt Issuance Costs
Debt Issuance Costs
Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated.
Asset Retirement Obligations
Asset Retirement Obligations
Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.
Leases
Leases
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, 2025 and 2024, 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.
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 Accrued revenue and 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.
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.
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, and accounts payable approximate their fair value at December 31, 2025 and 2024 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.
Recent Accounting Pronouncements
Recent Accounting Pronouncements
In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures, which enhances the disclosures required for certain expense captions in the Partnership's annual and interim consolidated financial statements. The guidance is effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on its disclosures.
Earnings Per Unit
The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common 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.
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Schedule of Contract with Customer, Contract Asset and Receivable
The following table presents information about the Partnership's accrued revenue and accounts receivable:
December 31,
20252024
(in thousands)
Accrued revenue$62,679 $67,047 
Accounts receivable2,893 4,046 
Total accrued revenue and accounts receivable$65,572 $71,093 
Schedule of Accrued Liabilities
Accrued liabilities consisted of the following:
 December 31,
 20252024
 (in thousands)
Accrued liabilities:
Accrued incentive compensation$7,824 $8,356 
Accrued general and administrative847 954 
Accrued property taxes6,029 6,498 
Accrued lease operating expenses1,985 713 
Accrued seismic costs1,500 — 
Accrued other1,203 721 
Total accrued liabilities$19,388 $17,242 
v3.25.4
ASSET RETIREMENT OBLIGATIONS (Tables)
 12 Months Ended
Dec. 31, 2025
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,
 20252024
 (in thousands)
Beginning asset retirement obligations$21,318 $20,267 
Liabilities incurred30 46 
Liabilities settled(774)(713)
Accretion expense1,374 1,298 
Revisions in estimated costs2,330 953 
Dispositions(13)(533)
Ending asset retirement obligations$24,265 $21,318 
Current asset retirement obligations$1,549 $2,032 
Noncurrent asset retirement obligations$22,716 $19,286 
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule 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, 2025
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
  (in thousands)
Assets:    
       Current assetCommodity derivative assets, net$24,930 $(6,066)$18,864 
       Long-term assetDeferred charges and other long-term assets4,325 (196)4,129 
          Total assets $29,255 $(6,262)$22,993 
Liabilities:    
       Current liabilityCommodity derivative liabilities, net$6,066 $(6,066)$— 
       Long-term liabilityCommodity derivative liabilities, net196 (196)— 
         Total liabilities $6,262 $(6,262)$— 
  
As of December 31, 2024
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
  (in thousands)
Assets:    
       Current assetCommodity derivative assets, net$4,866 $(3,042)$1,824 
       Long-term assetDeferred charges and other long-term assets768 (768)— 
          Total assets $5,634 $(3,810)$1,824 
Liabilities:    
       Current liabilityCommodity derivative liabilities, net$6,894 $(3,042)$3,852 
       Long-term liabilityCommodity derivative liabilities, net12,349 (768)11,581 
          Total liabilities $19,243 $(3,810)$15,433 
Schedule of Changes in Fair Value of Company's Commodity Derivative Instruments
Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities), as well as net cash paid or received on settlements, are presented on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments, net and consist of the following for the periods presented:
 For the year ended December 31,
Derivatives not designated as hedging instruments202520242023
 (in thousands)
Beginning fair value of commodity derivative instruments$(13,609)$37,335 $28,941 
Gain (loss) on oil derivative instruments30,029 (6,591)3,888 
Gain (loss) on natural gas derivative instruments17,562 861 87,229 
Net cash paid (received) on settlements of oil derivative instruments(12,102)8,524 (2,653)
Net cash paid (received) on settlements of natural gas derivative instruments1,113 (53,738)(80,070)
Net change in fair value of commodity derivative instruments36,602 (50,944)8,394 
Ending fair value of commodity derivative instruments$22,993 $(13,609)$37,335 
Schedule of Open Derivative Contracts
The Partnership had the following open derivative contracts for oil as of December 31, 2025:
 Volume (MBbl)Weighted Average Price (per Bbl)Range (per Bbl)
Period and Type of ContractLowHigh
Oil Swap Contracts:    
2025
Fourth quarter185 $71.22 $70.02 $73.15 
2026    
First quarter615 64.39 62.00 67.35 
Second quarter615 64.39 62.00 67.35 
Third quarter615 64.39 62.00 67.35 
Fourth quarter615 64.39 62.00 67.35 
2027
First quarter180 59.56 58.85 60.10 
Second quarter180 59.56 58.85 60.10 
Third quarter180 59.56 58.85 60.10 
Fourth quarter180 59.56 58.85 60.10 

The Partnership had the following open derivative contracts for natural gas as of December 31, 2025:
 Volume (BBtu)Weighted Average Price (per MMBtu)Range (per MMBtu)
Period and Type of ContractLowHigh
Natural Gas Swap Contracts:    
2026
First quarter12,600 $3.73 $3.50 $4.46 
Second quarter12,740 3.73 3.50 4.46 
Third quarter12,880 3.73 3.50 4.46 
Fourth quarter12,880 3.73 3.50 4.46 
2027
First quarter6,300 $3.93 $3.85 $4.00 
Second quarter6,370 3.93 3.85 4.00 
Third quarter6,440 3.93 3.85 4.00 
Fourth quarter6,440 3.93 3.85 4.00 

The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2025:
 Volume (MBbl)Weighted Average Price (per MMBtu)Range (per MMBtu)
Period and Type of ContractLowHigh
Oil Swap Contracts:    
2027
First quarter150 $59.74 $58.13 $61.20 
Second quarter150 59.74 58.13 61.20 
Third quarter150 59.74 58.13 61.20 
Fourth quarter150 59.74 58.13 61.20 
v3.25.4
FAIR VALUE MEASUREMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: 
 Fair Value Measurements UsingEffect of  
 Level 1Level 2Level 3Counterparty NettingTotal
 (in thousands)
As of December 31, 2025     
Financial Assets     
Commodity derivative instruments$— $29,255 $— $(6,262)$22,993 
Financial Liabilities     
Commodity derivative instruments— 6,262 — (6,262)— 
As of December 31, 2024     
Financial Assets     
Commodity derivative instruments$— $5,634 $— $(3,810)$1,824 
Financial Liabilities     
Commodity derivative instruments— 19,243 — (3,810)15,433 
v3.25.4
INCENTIVE COMPENSATION (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Schedule of Information about Restricted Units
The following table summarizes information about restricted units for the year ended December 31, 2025.
Number of UnitsWeighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2024527,743 $15.48 
Granted392,928 15.11 
Vested(286,820)14.78 
Forfeited(95,971)15.58 
Unvested at December 31, 2025537,880 $15.57 
Schedule of Information about Performance Units
The following table summarizes information about performance units for the year ended December 31, 2025.  
Performance unitsNumber of Units
Weighted-Average Grant-Date
Fair Value per Unit
Unvested at December 31, 2024800,162 $14.71 
Granted1
393,443 15.10 
Vested(354,158)12.78 
Forfeited(96,595)15.57 
Unvested at December 31, 2025742,852 $15.73 
1  Includes 515 of additional performance units issued based on the final performance multiplier for awards that vested in the period.
Schedule 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, 2025, 2024, and 2023.
 Year Ended December 31,
Incentive compensation expense202520242023
 (in thousands)
Cash — short and long-term incentive plan$5,053 $4,940 $4,442 
Equity-based compensation — restricted common units4,210 3,982 3,852 
Equity-based compensation — restricted performance units3,247 2,284 4,774 
Board of Directors incentive plan2,163 2,298 2,203 
Total incentive compensation expense$14,673 $13,504 $15,271 
v3.25.4
EARNINGS PER UNIT (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Schedule of Computation of Basic and Diluted Earnings per Unit
The following table sets forth the computation of basic and diluted earnings per unit:
 For the Year Ended December 31,
 202520242023
 (in thousands, except per unit amounts)
NET INCOME$299,932 $271,326 $422,549 
Distributions on Series B cumulative convertible preferred units (29,466)(29,466)(21,776)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS$270,466 $241,860 $400,773 
ALLOCATION OF NET INCOME:   
General partner interest$— $— $— 
Common units270,466 241,860 400,773 
 $270,466 $241,860 $400,773 
NUMERATOR:
Numerator for basic EPU - net income attributable to common unitholders$270,466 $241,860 $400,773 
Effect of dilutive securities— — 21,776 
Numerator for diluted EPU - net income attributable to common unitholders after the effect of dilutive securities$270,466 $241,860 $422,549 
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)211,667 210,684 209,970 
Effect of dilutive securities
62 96 15,135 
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities211,729 210,780 225,105 
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:   
Per common unit (basic)$1.28 $1.15 $1.91 
Per common unit (diluted)$1.28 $1.15 $1.88 
Schedule of Potentially Dilutive 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,
202520242023
(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis15,072 15,072 — 
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED (Tables)
 12 Months Ended
Dec. 31, 2025
Oil and Gas Disclosure [Abstract]  
Schedule of 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,
 202520242023
 (in thousands)
Acquisition Costs of Properties1:
   
Proved$346 $2,894 $— 
Unproved114,122 107,537 14,605 
Development Costs1
11,757 4,208 4,601 
Total$126,225 $114,639 $19,206 
 
1 Unproved properties include purchases of leasehold prospects.
Schedule of 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,
 20252024
 (in thousands)
Proved properties$2,015,631 $2,132,429 
Unproved properties1,063,709 973,028 
Total3,079,340 3,105,457 
Accumulated depreciation, depletion, amortization, and impairment(1,855,332)(1,973,460)
Oil and natural gas properties, net$1,224,008 $1,131,997 
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 $66.01, $76.32, and $78.21 per barrel as of December 31, 2025, 2024, and 2023, 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 $3.39, $2.13, and $2.64 per MMBtu as of December 31, 2025, 2024, and 2023, 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 $63.40 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2025, $74.14 per barrel for oil and $2.22 per Mcf for natural gas as of December 31, 2024, and $76.90 per barrel for oil and $2.63 per Mcf for natural gas as of December 31, 2023.
 Crude Oil (MBbl)Natural Gas (MMcf)Total (MBoe)
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 additions2
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 
Revisions of previous estimates1
119 (25,218)(4,084)
Purchases of minerals in place3
10 314 62 
Sales of minerals in place4
(163)(1,250)(371)
Extensions, discoveries and other additions2
2,015 56,323 11,402 
Production(3,606)(62,984)(14,103)
Net proved reserves at December 31, 2024
17,466 239,481 57,380 
Revisions of previous estimates1
669 (2,732)214 
Purchases of minerals in place3
70 943 227 
Sales of minerals in place4
(24)(75)(37)
Extensions, discoveries and other additions2
1,714 47,877 9,693 
Production(3,259)(56,237)(12,632)
Net proved reserves at December 31, 2025
16,636 229,257 54,845 
Net Proved Developed Reserves   
December 31, 202319,091 228,061 57,101 
December 31, 202417,466 220,901 54,283 
December 31, 202516,241 191,632 48,179 
Net Proved Undeveloped Reserves   
December 31, 2023— 44,235 7,373 
December 31, 2024— 18,580 3,097 
December 31, 2025395 37,625 6,666 
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 extensions and additions related to drilling activities in multiple areas, primarily within the Haynesville/Bossier play trend and the Permian Basin.
3 Includes the acquisition of mineral and royalty reserves primarily within the Haynesville/Bossier play trend.
4 Includes divestitures of working interest reserves primarily within the Austin Chalk play trend.
Schedule of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves
 Year Ended December 31,
 202520242023
 (in thousands)
Future cash inflows$1,828,128 $1,827,316 $2,184,038 
Future production costs(178,506)(164,886)(211,826)
Future development costs(63,833)(62,137)(61,723)
Future income tax expense(5,753)(5,433)(6,259)
Future net cash flows (undiscounted)1,580,036 1,594,860 1,904,230 
Annual discount 10% for estimated timing
(690,837)(726,773)(884,720)
Total$889,199 $868,087 $1,019,510 
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,
 202520242023
 (in thousands)
Standardized measure, beginning of year$868,087 $1,019,510 $1,665,011 
Sales, net of production costs(351,813)(367,686)(420,228)
Net changes in prices and production costs related to future production44,268 (51,740)(649,695)
Extensions, discoveries and improved recovery, net of future production and development costs179,769 174,145 295,413 
Previously estimated development costs incurred during the period— — — 
Revisions of estimated future development costs(551)(123)(4,221)
Revisions of previous quantity estimates, net of related costs4,526 (65,903)(78,139)
Accretion of discount87,104 102,292 167,064 
Purchases of reserves in place, less related costs3,700 572 — 
Sales of reserves in place(795)(5,194)— 
Changes in timing and other54,904 62,214 44,305 
Net increase (decrease) in standardized measures21,112 (151,423)(645,501)
Standardized measure, end of year$889,199 $868,087 $1,019,510 
v3.25.4
BUSINESS AND BASIS OF PRESENTATION (Details)
 12 Months Ended
Dec. 31, 2025
segment
state
Limited Partners Capital Account [Line Items]  
Number of operating segments 1
Number of reportable segments 1
U.S.  
Limited Partners Capital Account [Line Items]  
Number of states major onshore oil and natural gas basins located | state 41
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Summary Of Significant Accounting Polices [Line Items]      
Depreciation, depletion, and amortization $ 36,887 $ 45,196 $ 45,683
Amortization of debt issuance costs 1,100 1,100 1,000
Oil and Natural Gas Properties      
Summary Of Significant Accounting Polices [Line Items]      
Depreciation, depletion, and amortization 35,700 44,800 45,000
Other Property and Equipment      
Summary Of Significant Accounting Polices [Line Items]      
Depreciation, depletion, and amortization $ 1,200 $ 400 $ 700
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    
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accrued Revenue and Accounts Receivable (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Accounting Policies [Abstract]    
Accrued revenue $ 62,679 $ 67,047
Accounts receivable 2,893 4,046
Total accrued revenue and accounts receivable $ 65,572 $ 71,093
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accrued Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Accounting Policies [Abstract]    
Accrued incentive compensation $ 7,824 $ 8,356
Accrued general and administrative 847 954
Accrued property taxes 6,029 6,498
Accrued lease operating expenses 1,985 713
Accrued seismic costs 1,500 0
Accrued other 1,203 721
Total accrued liabilities $ 19,388 $ 17,242
v3.25.4
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]      
Beginning asset retirement obligations $ 21,318 $ 20,267  
Liabilities incurred 30 46  
Liabilities settled (774) (713)  
Accretion expense 1,374 1,298 $ 1,042
Revisions in estimated costs 2,330 953  
Dispositions (13) (533)  
Ending asset retirement obligations 24,265 21,318 $ 20,267
Current asset retirement obligations 1,549 2,032  
Noncurrent asset retirement obligations $ 22,716 $ 19,286  
v3.25.4
OIL AND NATURAL GAS PROPERTIES - Acquisitions (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Business Combination [Line Items]      
Aggregate cash consideration $ 107,052 $ 109,393 $ 14,605
Unproved Oil And Natural Gas Properties      
Business Combination [Line Items]      
Total consideration 114,500 110,400 $ 14,600
Aggregate cash consideration 107,100 109,400  
Common unit consideration for acquisition $ 7,400 $ 1,000  
v3.25.4
OIL AND NATURAL GAS PROPERTIES - Asset Exchange (Details) - a
Mar. 31, 2025
Feb. 28, 2025
Jul. 31, 2024
LOUISIANA | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations      
Asset Acquisition [Line Items]      
Net acres 900    
MISSISSIPPI | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations      
Asset Acquisition [Line Items]      
Net acres   3,700 51,000
Asset Exchange | TEXAS      
Asset Acquisition [Line Items]      
Net acres 2,900 2,100 8,000
v3.25.4
OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details)
 1 Months Ended
Jun. 30, 2025
Angelina, Nacogdoches, And San Augustine Counties  
Productive Wells [Line Items]  
Asset acquisition, ownership interest, in wells operated by others, gross, percent 35.00%
v3.25.4
OIL AND NATURAL GAS PROPERTIES - Impairment of Oil and Natural Gas Properties (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]      
Impairment of oil and natural gas properties $ 0 $ 0 $ 0
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details)
Dec. 31, 2025
counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Number of counterparties 8
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Schedule of Fair Value and Classification of Derivative Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Derivatives Fair Value [Line Items]    
Gross fair value, assets $ 29,255 $ 5,634
Effect of counterparty netting, assets (6,262) (3,810)
Total net carrying value on balance sheet, assets 22,993 1,824
Gross fair value, liabilities 6,262 19,243
Effect of counterparty netting, liabilities (6,262) (3,810)
Total net carrying value on balance sheet, liabilities 0 15,433
Commodity derivative assets, net    
Derivatives Fair Value [Line Items]    
Gross fair value, assets 24,930 4,866
Effect of counterparty netting, assets (6,066) (3,042)
Total net carrying value on balance sheet, assets 18,864 1,824
Deferred charges and other long-term assets    
Derivatives Fair Value [Line Items]    
Gross fair value, assets 4,325 768
Effect of counterparty netting, assets (196) (768)
Total net carrying value on balance sheet, assets 4,129 0
Commodity derivative liabilities, net    
Derivatives Fair Value [Line Items]    
Gross fair value, liabilities 6,066 6,894
Effect of counterparty netting, liabilities (6,066) (3,042)
Total net carrying value on balance sheet, liabilities 0 3,852
Commodity derivative liabilities, net    
Derivatives Fair Value [Line Items]    
Gross fair value, liabilities 196 12,349
Effect of counterparty netting, liabilities (196) (768)
Total net carrying value on balance sheet, liabilities $ 0 $ 11,581
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Schedule of Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivatives used in Net Investment Hedge, Net of Tax [Roll Forward]      
Gain (loss) on derivative instruments $ 47,591 $ (5,730) $ 91,117
Net cash paid (received) on settlements of derivative instruments (10,989) (45,214) (82,723)
Derivatives not designated as hedging instruments      
Derivatives used in Net Investment Hedge, Net of Tax [Roll Forward]      
Beginning fair value of commodity derivative instruments (13,609) 37,335 28,941
Net change in fair value of commodity derivative instruments 36,602 (50,944) 8,394
Ending fair value of commodity derivative instruments 22,993 (13,609) 37,335
Oil Swap Contracts: | Derivatives not designated as hedging instruments      
Derivatives used in Net Investment Hedge, Net of Tax [Roll Forward]      
Gain (loss) on derivative instruments 30,029 (6,591) 3,888
Net cash paid (received) on settlements of derivative instruments (12,102) 8,524 (2,653)
Natural Gas Swap Contracts: | Derivatives not designated as hedging instruments      
Derivatives used in Net Investment Hedge, Net of Tax [Roll Forward]      
Gain (loss) on derivative instruments 17,562 861 87,229
Net cash paid (received) on settlements of derivative instruments $ 1,113 $ (53,738) $ (80,070)
v3.25.4
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Schedule of Open Derivative Contracts for Oil and Natural Gas (Details) - Swap Contracts - Swap - Derivatives not designated as hedging instruments
MMBbls in Thousands, MMBTU in Thousands
 2 Months Ended 12 Months Ended
Feb. 24, 2026
$ / bbl
MMBbls
Dec. 31, 2025
MMBTU
$ / bbl
$ / MMBTU
MMBbls
Fourth Quarter 2025 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   185
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   71.22
Derivative contract, price range low (in USD per Bbl or MMBtu)   70.02
Derivative contract, price range high (in USD per Bbl or MMBtu)   73.15
First Quarter 2026 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   615
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   64.39
Derivative contract, price range low (in USD per Bbl or MMBtu)   62.00
Derivative contract, price range high (in USD per Bbl or MMBtu)   67.35
First Quarter 2026 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   12,600
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.73
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.50
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.46
Second Quarter 2026 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   615
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   64.39
Derivative contract, price range low (in USD per Bbl or MMBtu)   62.00
Derivative contract, price range high (in USD per Bbl or MMBtu)   67.35
Second Quarter 2026 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   12,740
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.73
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.50
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.46
Third Quarter 2026 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   615
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   64.39
Derivative contract, price range low (in USD per Bbl or MMBtu)   62.00
Derivative contract, price range high (in USD per Bbl or MMBtu)   67.35
Third Quarter 2026 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   12,880
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.73
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.50
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.46
Fourth Quarter 2026 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   615
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   64.39
Derivative contract, price range low (in USD per Bbl or MMBtu)   62.00
Derivative contract, price range high (in USD per Bbl or MMBtu)   67.35
Fourth Quarter 2026 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   12,880
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.73
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.50
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.46
First Quarter 2027 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   180
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   59.56
Derivative contract, price range low (in USD per Bbl or MMBtu)   58.85
Derivative contract, price range high (in USD per Bbl or MMBtu)   60.10
First Quarter 2027 | Oil Swap Contracts: | Subsequent Event    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls 150  
Derivative contract, weighted average price (in USD per Bbl or MMBtu) 59.74  
Derivative contract, price range low (in USD per Bbl or MMBtu) 58.13  
Derivative contract, price range high (in USD per Bbl or MMBtu) 61.20  
First Quarter 2027 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   6,300
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.93
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.85
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.00
Second Quarter 2027 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   180
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   59.56
Derivative contract, price range low (in USD per Bbl or MMBtu)   58.85
Derivative contract, price range high (in USD per Bbl or MMBtu)   60.10
Second Quarter 2027 | Oil Swap Contracts: | Subsequent Event    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls 150  
Derivative contract, weighted average price (in USD per Bbl or MMBtu) 59.74  
Derivative contract, price range low (in USD per Bbl or MMBtu) 58.13  
Derivative contract, price range high (in USD per Bbl or MMBtu) 61.20  
Second Quarter 2027 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   6,370
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.93
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.85
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.00
Third Quarter 2027 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   180
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   59.56
Derivative contract, price range low (in USD per Bbl or MMBtu)   58.85
Derivative contract, price range high (in USD per Bbl or MMBtu)   60.10
Third Quarter 2027 | Oil Swap Contracts: | Subsequent Event    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls 150  
Derivative contract, weighted average price (in USD per Bbl or MMBtu) 59.74  
Derivative contract, price range low (in USD per Bbl or MMBtu) 58.13  
Derivative contract, price range high (in USD per Bbl or MMBtu) 61.20  
Third Quarter 2027 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   6,440
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.93
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.85
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.00
Fourth Quarter 2027 | Oil Swap Contracts:    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls   180
Derivative contract, weighted average price (in USD per Bbl or MMBtu)   59.56
Derivative contract, price range low (in USD per Bbl or MMBtu)   58.85
Derivative contract, price range high (in USD per Bbl or MMBtu)   60.10
Fourth Quarter 2027 | Oil Swap Contracts: | Subsequent Event    
Derivative [Line Items]    
Derivative contract, volume (in MBbl) | MMBbls 150  
Derivative contract, weighted average price (in USD per Bbl or MMBtu) 59.74  
Derivative contract, price range low (in USD per Bbl or MMBtu) 58.13  
Derivative contract, price range high (in USD per Bbl or MMBtu) 61.20  
Fourth Quarter 2027 | Natural gas and natural gas liquids sales    
Derivative [Line Items]    
Derivative contract, volume (in BBtu) | MMBTU   6,440
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU   3.93
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU   3.85
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU   4.00
v3.25.4
FAIR VALUE MEASUREMENTS (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]    
Gross fair value, assets $ 29,255 $ 5,634
Effect of counterparty netting, assets (6,262) (3,810)
Total net carrying value on balance sheet, assets 22,993 1,824
Gross fair value, liabilities 6,262 19,243
Effect of counterparty netting, liabilities (6,262) (3,810)
Total net carrying value on balance sheet, liabilities 0 15,433
Commodity derivative instruments    
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]    
Effect of counterparty netting, assets (6,262) (3,810)
Total net carrying value on balance sheet, assets 22,993 1,824
Effect of counterparty netting, liabilities (6,262) (3,810)
Total net carrying value on balance sheet, liabilities 0 15,433
Commodity derivative instruments | 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 | Level 2    
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]    
Gross fair value, assets 29,255 5,634
Gross fair value, liabilities 6,262 19,243
Commodity derivative instruments | 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
v3.25.4
SIGNIFICANT OPERATORS (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Lease Revenue | Customer Concentration Risk | XTO Energy Inc.    
Concentration Risk [Line Items]    
Total revenue represented by one company 14.00% 13.00%
v3.25.4
CREDIT FACILITY (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Apr. 30, 2025
USD ($)
Nov. 30, 2024
USD ($)
Apr. 30, 2024
USD ($)
Line Of Credit Facility [Line Items]          
Number of lenders 0.667        
Current borrowing base (as a percent) 5.00%        
Aggregate principal balance outstanding $ 154,000 $ 25,000      
Revolving Credit Facility | Senior Line of Credit          
Line Of Credit Facility [Line Items]          
Maximum borrowing capacity $ 1,000,000        
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (as a percent) 10.00%        
Borrowing base     $ 580,000 $ 580,000 $ 580,000
Increase limit     $ 375,000 $ 375,000 $ 375,000
Weighted average interest rate (as a percent) 7.03% 7.50%      
Interest payable, term 90 days        
Availability of lenders' commitments, distributions not permitted (as a percent) 10.00%        
Ratio of total debt to EBITDAX, distributions not permitted 3.0        
Aggregate principal balance outstanding $ 154,000 $ 25,000      
Unused portion of current borrowing base $ 221,000 $ 350,000      
Revolving Credit Facility | Senior Line of Credit | Minimum          
Line Of Credit Facility [Line Items]          
Interest payable, term 90 days        
Current ratio 1.0        
Revolving Credit Facility | Senior Line of Credit | Maximum          
Line Of Credit Facility [Line Items]          
Ratio of total debt to EBITDAX 3.5        
Revolving Credit Facility | Senior Line of Credit | Prime Rate Plus Margin Rate | Minimum          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 1.50% 1.50%      
Revolving Credit Facility | Senior Line of Credit | Prime Rate Plus Margin Rate | Maximum          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 2.50% 2.50%      
Revolving Credit Facility | Senior Line of Credit | Federal Funds Effective Rate          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 0.50%        
Revolving Credit Facility | Senior Line of Credit | Adjusted Term Secured Overnight Funds Rate          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 0.10%        
Revolving Credit Facility | Senior Line of Credit | Adjusted Term Secured Overnight Funds Rate | Maximum          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 1.00%        
Revolving Credit Facility | Senior Line of Credit | Secured Overnight Financing Rate (SOFR) | Minimum          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 2.50% 2.50%      
Revolving Credit Facility | Senior Line of Credit | Secured Overnight Financing Rate (SOFR) | Maximum          
Line Of Credit Facility [Line Items]          
Interest rate (as a percent) 3.50% 3.50%      
Revolving Credit Facility | Senior Line of Credit | Borrowing Base Utilization Percentage Less Than 50%          
Line Of Credit Facility [Line Items]          
Commitment fee payable rate (as a percent) 0.375%        
Revolving Credit Facility | Senior Line of Credit | Borrowing Base Utilization Percentage Equal to or Greater Than 50%          
Line Of Credit Facility [Line Items]          
Commitment fee payable rate (as a percent) 0.50%        
v3.25.4
INCENTIVE COMPENSATION - Schedule of Information about Restricted Units (Details) - Restricted Common Units - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Number of Units      
Unvested, beginning of period (in shares) 527,743    
Granted (in shares) 392,928    
Vested (in shares) (286,820)    
Forfeited (in shares) (95,971)    
Unvested, end of period (in shares) 537,880 527,743  
Weighted-Average Grant-Date Fair Value per Unit      
Unvested, beginning of period (in dollars per share) $ 15.48    
Granted (in dollars per share) 15.11 $ 16.39 $ 16.03
Vested (in dollars per share) 14.78    
Forfeited (in dollars per share) 15.58    
Unvested, end of period (in dollars per share) $ 15.57 $ 15.48  
v3.25.4
INCENTIVE COMPENSATION - Narrative (Details)
$ / shares in Units, MMBoe in Thousands
 1 Months Ended 12 Months Ended
Mar. 31, 2022
MMBoe
Dec. 31, 2025
USD ($)
commonUnit
$ / shares
Dec. 31, 2024
USD ($)
$ / shares
Dec. 31, 2023
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 dollars per share) | $ / shares   $ 15.11 $ 16.39 $ 16.03
Unrecognized compensation cost   $ 4,600,000    
Period of weighted average recognition   1 year 8 months 26 days    
Fair value of units vested   $ 4,100,000 $ 5,000,000.0 $ 6,200,000
Performance Units        
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]        
Granted (in dollars per share) | $ / shares   $ 15.10 $ 15.11 $ 14.54
Unrecognized compensation cost   $ 3,700,000    
Period of weighted average recognition   1 year 10 months 24 days    
Fair value of units vested   $ 5,200,000 $ 6,300,000 $ 8,000,000.0
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]        
Minimum daily oil production | MMBoe 42      
v3.25.4
INCENTIVE COMPENSATION - Schedule of Information about Performance Units (Details) - Performance Units - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Number of Units      
Unvested, beginning of period (in shares) 800,162    
Granted (in shares) 393,443    
Vested (in shares) (354,158)    
Forfeited (in shares) (96,595)    
Unvested, end of period (in shares) 742,852 800,162  
Weighted-Average Grant-Date Fair Value per Unit      
Unvested, beginning of period (in dollars per share) $ 14.71    
Granted (in dollars per share) 15.10 $ 15.11 $ 14.54
Vested (in dollars per share) 12.78    
Forfeited (in dollars per share) 15.57    
Unvested, end of period (in dollars per share) $ 15.73 $ 14.71  
Additional shares authorized (in shares) 515    
v3.25.4
INCENTIVE COMPENSATION - Schedule of Incentive Compensation Expense (Details) - General and Administrative Expense - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Cash — short and long-term incentive plan $ 5,053 $ 4,940 $ 4,442
Total incentive compensation expense 14,673 13,504 15,271
Restricted Common Units      
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Equity-based compensation expense 4,210 3,982 3,852
Restricted Performance Units      
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Equity-based compensation expense 3,247 2,284 4,774
Common units | Board of Directors      
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Total incentive compensation expense $ 2,163 $ 2,298 $ 2,203
v3.25.4
EMPLOYEE BENEFIT PLANS (Details) - 401(k) Plan - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Contribution Plan Disclosure [Line Items]      
Maximum tax-deferred contributions 90.00%    
Partnership's defined contributions $ 0.8 $ 0.7 $ 0.6
Maximum      
Defined Contribution Plan Disclosure [Line Items]      
Matching employee contributions 5.00%    
After One Year      
Defined Contribution Plan Disclosure [Line Items]      
Graded vesting percentage 33.00%    
Vesting period 1 year    
After Two Years      
Defined Contribution Plan Disclosure [Line Items]      
Graded vesting percentage 66.00%    
Vesting period 2 years    
After Three Years      
Defined Contribution Plan Disclosure [Line Items]      
Graded vesting percentage 100.00%    
Vesting period 3 years    
Service period 3 years    
v3.25.4
COMMITMENTS AND CONTINGENCIES (Details)
Dec. 31, 2025
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
Provision for remediation costs $ 0
v3.25.4
PREFERRED UNITS (Details) - Preferred Units
$ / shares in Units, $ in Thousands
Nov. 28, 2025
Nov. 28, 2023
Nov. 28, 2017
USD ($)
businessDay
$ / shares
shares
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Class of Stock [Line Items]          
Shares, price per share (in dollars per share) | $ / shares     $ 20.39    
Proceeds from issuance of convertible preferred stock     $ 300,000    
Preferred units distribution rate 9.80% 9.80% 7.00%    
Preferred stock liquidation preference     $ 315,000    
Preferred stock, dividend distribution terms, period of readjustment   2 years      
Preferred stock, dividend distribution terms, percent per annum increase   5.50%      
Distribution rate increase if quarterly distributions are accrued and unpaid, percentage   2.00%      
Stated liquidation preference (in dollars per share) | $ / shares     $ 21.41    
Preferred unit conversion ratio     1    
Minimum underlying value for conversion trigger     $ 10,000    
Redemption amount     $ 100,000    
Period of redemption restriction     90 days    
Redemption notice period | businessDay     20    
Preferred units, outstanding value       $ 300,478 $ 300,478
Accrued distributions       $ 7,400 $ 7,400
Noble Acquisition          
Class of Stock [Line Items]          
Number of shares issued (in shares) | shares     14,711,219    
v3.25.4
EARNINGS PER UNIT - Schedule of Computation of Basic and Diluted Earnings per Unit (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share [Abstract]      
NET INCOME $ 299,932 $ 271,326 $ 422,549
Distributions on Series B cumulative convertible preferred units (29,466) (29,466) (21,776)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS 270,466 241,860 400,773
ALLOCATION OF NET INCOME:      
General partner interest 0 0 0
Common units 270,466 241,860 400,773
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS 270,466 241,860 400,773
NUMERATOR:      
Numerator for basic EPU - net income attributable to common unitholders 270,466 241,860 400,773
Effect of dilutive securities 0 0 21,776
Numerator for diluted EPU - net income attributable to common unitholders after the effect of dilutive securities $ 270,466 $ 241,860 $ 422,549
DENOMINATOR:      
Denominator for basic EPU - weighted average common units outstanding (basic) (in shares) 211,667 210,684 209,970
Effect of dilutive securities (in shares) 62 96 15,135
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities (in shares) 211,729 210,780 225,105
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:      
Per common unit (basic) (in dollars per share) $ 1.28 $ 1.15 $ 1.91
Per common unit (diluted) (in dollars per share) $ 1.28 $ 1.15 $ 1.88
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Series B cumulative convertible preferred units on an as-converted basis | Common Units      
Earnings Per Share Basic [Line Items]      
Potentially dilutive securities (in shares) 15,072 15,072 0
v3.25.4
COMMON UNITS (Details) - USD ($)
$ in Millions
 12 Months Ended
Nov. 28, 2025
Nov. 28, 2023
Nov. 28, 2017
Dec. 31, 2025
Oct. 30, 2023
2023 Unit Repurchase Plan          
Class of Stock [Line Items]          
Stock authorized for repurchase amount         $ 150.0
Stock repurchased (in shares)       0  
2018 Unit Repurchase Plan          
Class of Stock [Line Items]          
Stock authorized for repurchase amount         $ 75.0
Preferred Units          
Class of Stock [Line Items]          
Preferred units minimum voting rights rate       15.00%  
Preferred units distribution rate 9.80% 9.80% 7.00%    
Preferred stock, dividend distribution terms, period of readjustment   2 years      
Preferred stock, dividend distribution terms, percent per annum increase   5.50%      
v3.25.4
SUBSEQUENT EVENTS (Details)
Feb. 05, 2026
$ / shares
Common units | Subsequent Event  
Subsequent Event [Line Items]  
Cash distribution declared (in dollars per share) $ 0.300
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED - Schedule of Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Acquisition Costs of Properties:      
Proved $ 346 $ 2,894 $ 0
Unproved 114,122 107,537 14,605
Development Costs 11,757 4,208 4,601
Total $ 126,225 $ 114,639 $ 19,206
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED - Schedule of Oil and Natural Gas Capitalized Costs (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Oil and Gas Disclosure [Abstract]    
Proved properties $ 2,015,631 $ 2,132,429
Unproved properties 1,063,709 973,028
Total 3,079,340 3,105,457
Accumulated depreciation, depletion, amortization, and impairment (1,855,332) (1,973,460)
Oil and natural gas properties, net $ 1,224,008 $ 1,131,997
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED - Schedule of Estimated Net Quantities of Partnership Proved, Proved Developed and Proved Undeveloped Oil and Natural Gas Reserve (Details)
 12 Months Ended
Dec. 31, 2025
MMBoe
$ / bbl
$ / Mcf
$ / MMBTU
MMcf
MMBbls
Dec. 31, 2024
MMBoe
MBoe
$ / bbl
$ / MMBTU
$ / Mcf
MMcf
MMBbls
MBbls
Dec. 31, 2023
MMBoe
$ / bbl
$ / Mcf
$ / 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 57,380 64,474 64,115
Revisions of previous estimates | MMBoe 214 (4,084) (2,754)
Purchases of minerals in place 227 62  
Sales of minerals in place (37) (371)  
Extensions, discoveries and other additions | MMBoe 9,693 11,402 17,645
Production | MMBoe (12,632) (14,103) (14,532)
Balance at the end of the period | MMBoe 54,845 57,380 64,474
Net Proved Developed Reserves | MMBoe 48,179 54,283 57,101
Net Proved Undeveloped Reserves | MMBoe 6,666 3,097 7,373
Crude Oil      
Reserve Quantities [Line Items]      
Average sale price (in dollars per share) | $ / bbl 66.01 76.32 78.21
Average adjusted sale price | $ / bbl 63.40 74.14 76.90
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 17,466 19,091 19,184
Revisions of previous estimates | MMBbls 669 119 675
Purchases of minerals in place 70 10  
Sales of minerals in place (24) (163)  
Extensions, discoveries and other additions | MMBbls 1,714 2,015 2,989
Production | MMBbls (3,259) (3,606) (3,757)
Balance at the End of the period | MMBbls 16,636 17,466 19,091
Net Proved Developed Reserves | MMBbls 16,241 17,466 19,091
Net Proved Undeveloped Reserves | MMBbls 395 0 0
Natural Gas Reserves      
Reserve Quantities [Line Items]      
Average sale price (in dollars per share) | $ / MMBTU 3.39 2.13 2.64
Average adjusted sale price | $ / Mcf 3.37 2.22 2.63
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 239,481 272,296 269,586
Revisions of previous estimates (2,732) (25,218) (20,578)
Purchases of minerals in place 943 314  
Sales of minerals in place (75) (1,250)  
Extensions, discoveries and other additions 47,877 56,323 87,935
Production (56,237) (62,984) (64,647)
Balance at the End of the period 229,257 239,481 272,296
Net Proved Developed Reserves 191,632 220,901 228,061
Net Proved Undeveloped Reserves 37,625 18,580 44,235
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Oil and Gas Disclosure [Abstract]        
Future cash inflows $ 1,828,128 $ 1,827,316 $ 2,184,038  
Future production costs (178,506) (164,886) (211,826)  
Future development costs (63,833) (62,137) (61,723)  
Future income tax expense (5,753) (5,433) (6,259)  
Future net cash flows (undiscounted) 1,580,036 1,594,860 1,904,230  
Annual discount 10% for estimated timing (690,837) (726,773) (884,720)  
Total $ 889,199 $ 868,087 $ 1,019,510 $ 1,665,011
v3.25.4
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
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 $ 868,087 $ 1,019,510 $ 1,665,011
Sales, net of production costs (351,813) (367,686) (420,228)
Net changes in prices and production costs related to future production 44,268 (51,740) (649,695)
Extensions, discoveries and improved recovery, net of future production and development costs 179,769 174,145 295,413
Previously estimated development costs incurred during the period 0 0 0
Revisions of estimated future development costs (551) (123) (4,221)
Revisions of previous quantity estimates, net of related costs 4,526 (65,903) (78,139)
Accretion of discount 87,104 102,292 167,064
Purchases of reserves in place, less related costs 3,700 572 0
Sales of reserves in place (795) (5,194) 0
Changes in timing and other 54,904 62,214 44,305
Net increase (decrease) in standardized measures 21,112 (151,423) (645,501)
Standardized measure, end of year $ 889,199 $ 868,087 $ 1,019,510