Black Stone Minerals (BSM) 10-Q 5 Nov 24 2024 Q3 Quarterly report Financial data

COVER

COVER - shares	9 Months Ended
	Sep. 30, 2024	Nov. 01, 2024
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2024
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 Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Smaller reporting company	false
Emerging growth company	false
Entity shell company	false
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Common units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		210,694,933
Series B Cumulative Convertible Preferred Units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
CURRENT ASSETS
Cash and cash equivalents	$ 20,963	$ 70,282
Accounts receivable	68,119	82,253
Commodity derivative assets	18,147	38,273
Prepaid expenses and other current assets	2,026	2,319
TOTAL CURRENT ASSETS	109,255	193,127
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $943,916 and $890,338 at September 30, 2024 and December 31, 2023, respectively	3,057,879	3,026,394
Accumulated depreciation, depletion, amortization, and impairment	(1,962,614)	(1,961,899)
Oil and natural gas properties, net	1,095,265	1,064,495
Other property and equipment, net of accumulated depreciation of $14,453 and $14,163 at September 30, 2024 and December 31, 2023, respectively	1,031	1,007
NET PROPERTY AND EQUIPMENT	1,096,296	1,065,502
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,266	8,255
TOTAL ASSETS	1,212,817	1,266,884
CURRENT LIABILITIES
Accounts payable	3,742	6,270
Accrued liabilities	13,913	17,003
Commodity derivative liabilities	0	1,229
Other current liabilities	1,803	1,334
TOTAL CURRENT LIABILITIES	19,458	25,836
LONG–TERM LIABILITIES
Accrued incentive compensation	1,082	1,699
Commodity derivative liabilities	3,008	81
Asset retirement obligations	18,751	19,030
Other long-term liabilities	2,217	2,893
TOTAL LIABILITIES	44,516	49,539
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY
Partners' equity – general partner interest	0	0
TOTAL EQUITY	867,823	918,208
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,212,817	1,266,884
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at September 30, 2024 and December 31, 2023	300,478	299,137
Common units
EQUITY
Partners' equity – common units, 210,688 and 209,991 units outstanding at September 30, 2024 and December 31, 2023, respectively	$ 867,823	$ 918,208

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Oil and natural gas properties, at cost, using the successful efforts method of accounting, unproved properties	$ 943,916	$ 890,338
Other property and equipment, accumulated depreciation	$ 14,453	$ 14,163
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common units
Partners' equity - units, outstanding (in shares)	210,688	209,991

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
REVENUE
Revenue from contracts with customers	$ 103,181	$ 136,719	$ 335,135	$ 364,723
Gain (loss) on commodity derivative instruments	31,675	(26,922)	14,838	36,652
TOTAL REVENUE	134,856	109,797	349,973	401,375
OPERATING (INCOME) EXPENSE
Lease operating expense	2,422	2,615	7,433	8,149
Production costs and ad valorem taxes	12,369	16,441	38,876	41,952
Exploration expense	2,562	1,711	2,579	1,719
Depreciation, depletion, and amortization	11,258	12,367	34,253	33,935
General and administrative	12,801	14,448	40,286	38,950
Accretion of asset retirement obligations	324	254	962	749
(Gain) loss on sale of assets, net	0	(73)	0	(73)
TOTAL OPERATING EXPENSE	41,736	47,763	124,389	125,381
INCOME (LOSS) FROM OPERATIONS	93,120	62,034	225,584	275,994
OTHER INCOME (EXPENSE)
Interest and investment income	344	511	1,476	1,041
Interest expense	(724)	(621)	(1,979)	(2,080)
Other income (expense)	(9)	143	(101)	(53)
TOTAL OTHER INCOME (EXPENSE)	(389)	33	(604)	(1,092)
NET INCOME (LOSS)	92,731	62,067	224,980	274,902
Distributions on Series B cumulative convertible preferred units	(7,366)	(5,250)	(22,099)	(15,750)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	85,365	56,817	202,881	259,152
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
Common units	85,365	56,817	202,881	259,152
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 85,365	$ 56,817	$ 202,881	$ 259,152
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.41	$ 0.27	$ 0.96	$ 1.23
Per common unit (diluted) (in dollars per share)	$ 0.41	$ 0.27	$ 0.96	$ 1.22
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic) (in shares)	210,687	209,982	210,680	209,963
Weighted average common units outstanding (diluted) (in shares)	210,687	209,982	210,680	224,932
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 63,999	$ 85,724	$ 209,112	$ 208,184
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	37,039	48,815	115,543	147,857
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 2,143	$ 2,180	$ 10,480	$ 8,682

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common units	Partners' equity	Series B cumulative convertible preferred units Partners' equity
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)		914
Equity–based compensation			5,052
Distributions			(99,600)
Charges to partners' equity for accrued distribution equivalent rights			(733)
Distributions on Series B cumulative convertible preferred units				$ (5,250)
Net income (loss)			134,443
Ending balance (in shares) at Mar. 31, 2023		209,963
Ending balance at Mar. 31, 2023			939,867
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)		5
Equity–based compensation			2,076
Distributions			(99,734)
Charges to partners' equity for accrued distribution equivalent rights			(471)
Distributions on Series B cumulative convertible preferred units				(5,250)
Net income (loss)			78,392
Ending balance (in shares) at Jun. 30, 2023		209,968
Ending balance at Jun. 30, 2023			914,880
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)		18
Equity–based compensation			3,530
Distributions			(99,744)
Charges to partners' equity for accrued distribution equivalent rights			(461)
Distributions on Series B cumulative convertible preferred units				(5,250)
Net income (loss)			62,067
Ending balance (in shares) at Sep. 30, 2023		209,986
Ending balance at Sep. 30, 2023			875,022
Beginning balance (in shares) at Dec. 31, 2023		209,991
Beginning balance at Dec. 31, 2023	$ 918,208		918,208
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(287)
Repurchases of common units			(4,381)
Restricted units granted, net of forfeitures (in shares)		952
Equity–based compensation			5,431
Distributions			(99,899)
Charges to partners' equity for accrued distribution equivalent rights			(595)
Distributions on Series B cumulative convertible preferred units				(7,367)
Net income (loss)			63,927
Ending balance (in shares) at Mar. 31, 2024		210,656
Ending balance at Mar. 31, 2024			875,324
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(4)
Repurchases of common units			(68)
Issuance of common units for property acquisitions (in shares)		64
Issuance of common units for property acquisitions			1,039
Restricted units granted, net of forfeitures (in shares)		(34)
Equity–based compensation			1,935
Distributions			(79,014)
Charges to partners' equity for accrued distribution equivalent rights			(185)
Distributions on Series B cumulative convertible preferred units				(7,366)
Net income (loss)			68,322
Ending balance (in shares) at Jun. 30, 2024		210,682
Ending balance at Jun. 30, 2024			859,987
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)		6
Equity–based compensation			1,726
Distributions			(79,008)
Charges to partners' equity for accrued distribution equivalent rights			(247)
Distributions on Series B cumulative convertible preferred units				$ (7,366)
Net income (loss)			92,731
Ending balance (in shares) at Sep. 30, 2024		210,688
Ending balance at Sep. 30, 2024	$ 867,823		$ 867,823

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 224,980	$ 274,902
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	34,253	33,935
Accretion of asset retirement obligations	962	749
Amortization of deferred charges	807	775
(Gain) loss on commodity derivative instruments	(14,838)	(36,652)
Net cash (paid) received on settlement of commodity derivative instruments	36,480	65,658
Equity-based compensation	6,765	8,412
(Gain) loss on sale of assets, net	0	(73)
Changes in operating assets and liabilities:
Accounts receivable	14,206	48,146
Prepaid expenses and other current assets	293	(74)
Accounts payable, accrued liabilities, and other	(5,161)	(8,435)
Settlement of asset retirement obligations	(660)	(208)
NET CASH PROVIDED BY OPERATING ACTIVITIES	298,087	387,135
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(64,180)	(932)
Additions to oil and natural gas properties	(688)	(3,720)
Additions to oil and natural gas properties leasehold costs	(1,840)	(9)
Purchases of other property and equipment	(314)	(358)
Proceeds from the sale of oil and natural gas properties	2,795	73
NET CASH USED IN INVESTING ACTIVITIES	(64,227)	(4,946)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility	33,000	64,000
Repayments under credit facility	(33,000)	(74,000)
Debt issuance costs and other	(50)	(142)
NET CASH USED IN FINANCING ACTIVITIES	(283,179)	(330,466)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(49,319)	51,723
CASH AND CASH EQUIVALENTS – beginning of the period	70,282	4,307
CASH AND CASH EQUIVALENTS – end of the period	20,963	56,030
SUPPLEMENTAL DISCLOSURE
Interest paid	1,180	1,330
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(257,921)	(299,078)
Repurchases of common units	(4,449)	(5,496)
Series B Cumulative Convertible Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (20,759)	$ (15,750)

BUSINESS AND BASIS OF PRESENTAT

BUSINESS AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2024
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 unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023 ("2023 Annual Report on Form 10-K"). The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the nine months ended September 30, 2024 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income (loss) and equity in the accompanying unaudited interim consolidated financial statements. The unaudited interim 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 unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2024
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies Significant accounting policies are disclosed in the Partnership’s 2023 Annual Report on Form 10-K. There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2024. Accounts Receivable The following table presents information about the Partnership's accounts receivable: September 30, 2024 December 31, 2023 (in thousands) Accounts receivable: Revenues from contracts with customers $ 62,381 $ 77,560 Other 5,738 4,693 Total accounts receivable $ 68,119 $ 82,253 Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures (Topic 280), which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the amendments provide new segment disclosure requirements for entities with a single reportable segment. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Partnership does not plan to early adopt and expects the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	9 Months Ended
	Sep. 30, 2024
Extractive Industries [Abstract]
OIL AND NATURAL GAS PROPERTIES	OIL AND NATURAL GAS PROPERTIES Acquisitions Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. During the nine months ended September 30, 2024, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in the Gulf Coast land region from various sellers for an aggregate of $65.2 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $64.2 million in cash that was funded 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 consisted of unproved oil and natural gas properties in the Gulf Coast land region from various sellers for cash consideration of $14.6 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid was funded with cash from operating activities. Asset Exchange In the third quarter of 2024, the Partnership closed on a transaction with a third-party operator whereby the Partnership received 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. The acreage surrendered in Mississippi constituted a partial disposition of unproved property and no gain or loss was recognized on the transaction. Shelby Trough Development Agreements In 2020 and 2021, BSM entered into Joint Exploration Agreements ("JEAs") with Aethon Energy ("Aethon") to develop certain portions of the Partnership's undeveloped acreage in San Augustine County and Angelina County in East Texas. The agreements provide for minimum annual well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract areas. If Aethon drills more than the minimum commitment wells in a given program year, Aethon may reduce its minimum well commitment in future program years by the number of excess wells, which we refer to as "banked" wells. Aethon's ability to apply banked wells to reduce its drilling commitments is capped at three or four wells each year, depending on the JEA. The Partnership's development agreement and related drilling commitments covering its San Augustine County acreage are independent of the development agreement and associated commitments covering Angelina County. Under the JEAs, Aethon may elect to temporarily suspend its drilling obligations for up to nine In September 2024, the Partnership entered into letter agreements with Aethon to amend the JEAs in San Augustine and Angelina counties. In those agreements, the parties agreed to revise the current program year drill schedules under each JEA, to extend the respective program years by nine months, and to withdraw the invocation of the time-out provisions. Aethon also released its rights under 25,000 acres from the parties' area of mutual interest defined in the original JEAs. Upon the satisfaction of the current program year performance deadlines as described in the letter agreements, Aethon will have an inventory of ten banked wells in Angelina and one banked well in San Augustine. San Augustine County JEA The original San Augustine JEA called for a minimum of five wells to be drilled in the initial program year, which began in September 2021, 10 wells to be drilled in the second and third program years, and, thereafter, a minimum of 12 wells per year beginning with the fourth program year. As amended, the San Augustine JEA now provides for a minimum of nine wells to be drilled in the current (third) program year ending in May 2025, with a minimum of 12 wells to be drilled in the fourth program year scheduled to commence in June 2025 and each program year thereafter. As of September 30, 2024, Aethon had drilled three wells in the third program year under the San Augustine JEA. Angelina County JEA The original Angelina JEA called for a minimum of four wells to be drilled in the initial program year, which began in October 2020, 10 wells to be drilled in the second program year, and, thereafter, a minimum of 15 wells per year beginning with the third program year. As amended, the Angelina JEA now provides for a minimum 15 wells to be drilled in the current (fourth) program year ending in June 2025 and, each program year thereafter. As of September 30, 2024, Aethon had drilled four wells in the fourth program year under the Angelina JEA, two of which have been temporarily abandoned and scheduled for plugging as a result of mechanical issues. Farmout Agreements The Partnership has entered into farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lowering its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests. BSM's current farmout arrangements cover the Partnership's share of working interests under active development by Aethon in San Augustine County and Angelina County in East Texas. San Augustine County Farmout In May 2021, the Partnership entered into a farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). In April 2022, the Partnership amended the Canaan Farmout and entered into a farmout agreement (the "JWM Farmout") with JWM Oil & Gas LLC ("JWM"). These agreements continue for a 10-year period, unless earlier terminated in accordance with the terms of the agreements. The JWM Farmout terminated in September 2024, and the Partnership expects to enter into a new farmout arrangement with respect to the interests covered by the JWM Farmout in the fourth quarter of 2024. The Partnership’s farmout counterparties were obligated to fund the development of wells drilled by Aethon in the initial program year, and thereafter, have certain rights and options to continue funding the Partnership's working interest for the duration of each farmout agreement. The farmout counterparties each earn a percentage of the Partnership's working interest in wells drilled and operated by Aethon within the contract area subject to the agreements. The Partnership will receive an overriding royalty interest ("ORRI") before payout and an increased ORRI after payout on all wells drilled under the farmout agreements. The following tables present the working interests each farmout partner will earn within the contract area under the San Augustine farmout agreements: Brent Miller Area Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 64.0 % 32.0 % Azul 20.0 % 10.0 % Former JWM Interest 16.0 % 8.0 % Total 100.0 % 50.0 % Other Areas Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 40.0 % 10.0 % Azul 50.0 % 12.5 % Former JWM Interest 10.0 % 2.5 % Total 100.0 % 25.0 % Angelina County Farmout In November 2020, the Partnership entered into a farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Pivotal Farmout. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. Impairment of Oil and Natural Gas Properties Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership 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.

COMMODITY DERIVATIVE FINANCIAL

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2024
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 September 30, 2024, the Partnership’s open derivative 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 the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of September 30, 2024 and December 31, 2023. See "Note 5 - 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 September 30, 2024, the Partnership had seven counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under the Credit Facility. The tables below summarize the fair values and classifications 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: September 30, 2024 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 19,178 $ (1,031) $ 18,147 Long-term asset Deferred charges and other long-term assets 3,458 (2,904) 554 Total assets $ 22,636 $ (3,935) $ 18,701 Liabilities: Current liability Commodity derivative liabilities $ 1,031 $ (1,031) $ — Long-term liability Commodity derivative liabilities 5,912 (2,904) 3,008 Total liabilities $ 6,943 $ (3,935) $ 3,008 December 31, 2023 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 41,485 $ (3,212) $ 38,273 Long-term asset Deferred charges and other long-term assets 498 (126) 372 Total assets $ 41,983 $ (3,338) $ 38,645 Liabilities: Current liability Commodity derivative liabilities $ 4,441 $ (3,212) $ 1,229 Long-term liability Commodity derivative liabilities 207 (126) 81 Total liabilities $ 4,648 $ (3,338) $ 1,310 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, Derivatives not designated as hedging instruments 2024 2023 2024 2023 (in thousands) Beginning fair value of commodity derivative instruments $ (5,118) $ 51,046 $ 37,335 $ 28,941 Gain (loss) on oil derivative instruments 25,444 (36,013) 988 (21,232) Gain (loss) on natural gas derivative instruments 6,231 9,091 13,850 57,884 Net cash paid (received) on settlements of oil derivative instruments 3,852 (2,659) 9,257 (4,431) Net cash paid (received) on settlements of natural gas derivative instruments (14,716) (21,530) (45,737) (61,227) Net change in fair value of commodity derivative instruments 20,811 (51,111) (21,642) (29,006) Ending fair value of commodity derivative instruments $ 15,693 $ (65) $ 15,693 $ (65) The Partnership had the following open derivative contracts for oil as of September 30, 2024: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2024 Third Quarter 190,000 $ 71.45 $ 67.00 $ 81.00 Fourth Quarter 570,000 71.45 67.00 81.00 2025 First Quarter 555,000 $ 71.22 $ 70.02 $ 73.15 Second Quarter 555,000 71.22 70.02 73.15 Third Quarter 555,000 71.22 70.02 73.15 Fourth Quarter 555,000 71.22 70.02 73.15 2026 First Quarter 120,000 $ 65.85 $ 65.52 $ 66.23 Second Quarter 120,000 65.85 65.52 66.23 Third Quarter 120,000 65.85 65.52 66.23 Fourth Quarter 120,000 65.85 65.52 66.23 The Partnership had the following open derivative contracts for natural gas as of September 30, 2024: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2024 Fourth Quarter 10,580,000 $ 3.55 $ 3.00 $ 3.76 2025 First Quarter 10,800,000 $ 3.36 $ 3.02 $ 3.65 Second Quarter 10,920,000 3.36 3.02 3.65 Third Quarter 11,040,000 3.45 3.34 3.65 Fourth Quarter 11,040,000 3.45 3.34 3.65 2026 First Quarter 7,200,000 $ 3.52 $ 3.50 $ 3.57 Second Quarter 7,280,000 3.52 3.50 3.57 Third Quarter 7,360,000 3.52 3.50 3.57 Fourth Quarter 7,360,000 3.52 3.50 3.57 The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2024: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2026 First Quarter 60,000 $ 67.18 $ 67.00 $ 67.35 Second Quarter 60,000 67.18 67.00 67.35 Third Quarter 60,000 67.18 67.00 67.35 Fourth Quarter 60,000 67.18 67.00 67.35

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement , establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 —Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 —Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 —Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of fair value hierarchy for the nine months ended September 30, 2024 and 2023. 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 September 30, 2024 and December 31, 2023 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See "Note 4 - Commodity Derivative Financial Instruments" for additional information. The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of September 30, 2024 Financial Assets Commodity derivative instruments $ — $ 22,636 $ — $ (3,935) $ 18,701 Financial Liabilities Commodity derivative instruments $ — $ 6,943 $ — $ (3,935) $ 3,008 As of December 31, 2023 Financial Assets Commodity derivative instruments $ — $ 41,983 $ — $ (3,338) $ 38,645 Financial Liabilities Commodity derivative instruments $ — $ 4,648 $ — $ (3,338) $ 1,310 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership had no business combinations for the nine months ended September 30, 2024 or the year ended December 31, 2023. See "Note 3 - Oil and Natural Gas Properties". Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. The Partnership’s estimates of fair value 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 as of September 30, 2024 or December 31, 2023. There were no assets measured at fair value on a non-recurring basis for the nine months ended September 30, 2024 or the year ended December 31, 2023.

CREDIT FACILITY

CREDIT FACILITY	9 Months Ended
	Sep. 30, 2024
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, 2027. 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 April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million. The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2025. 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 secured overnight financing rate ("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 0.10%, which is referred to as Adjusted Term SOFR. 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) the Adjusted Term SOFR for a one-month tenor, plus 1.00%. As of December 31, 2023 and September 30, 2024, 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 8.04% during the nine months ended September 30, 2024 and 7.36% for the twelve months ended December 31, 2023. 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 September 30, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the unaudited interim 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 September 30, 2024 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

INCENTIVE COMPENSATION

INCENTIVE COMPENSATION	9 Months Ended
	Sep. 30, 2024
Share-Based Payment Arrangement [Abstract]
INCENTIVE COMPENSATION	INCENTIVE COMPENSATION The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands) Cash—short and long-term incentive plans $ 1,498 $ 1,303 $ 3,883 $ 3,236 Equity-based compensation—restricted common units 1,006 976 2,967 2,872 Equity-based compensation—restricted performance units 621 2,282 2,050 3,968 Board of Directors incentive plan 550 519 1,748 1,572 Total incentive compensation expense $ 3,675 $ 5,080 $ 10,648 $ 11,648 For the nine months ended September 30, 2024, the Partnership repurchased 291,163 common units at a weighted average price of $15.28 per unit for the purpose of satisfying tax withholding obligations upon the vesting of certain long-term incentive equity awards held by our executive officers and certain other employees. Specifically, when an employee's equity award vests, the Partnership withholds a portion of the units to cover the employee's tax liability.

PREFERRED UNITS

PREFERRED UNITS	9 Months Ended
	Sep. 30, 2024
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 approximately $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"). On November 28, 2023, the Distribution Rate was adjusted to 9.8% 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 Partnership cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions. The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.39, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Partnership has the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value. The Series B cumulative convertible preferred units had a carrying value of $300.5 million, including accrued distributions of $7.4 million, as of September 30, 2024 and a carrying value of $299.1 million, including accrued distributions of $6.0 million, as of December 31, 2023. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

EARNINGS PER UNIT

EARNINGS PER UNIT	9 Months Ended
	Sep. 30, 2024
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 common unit: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 92,731 $ 62,067 $ 224,980 $ 274,902 Distributions on Series B cumulative convertible preferred units (7,366) (5,250) (22,099) (15,750) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 85,365 $ 56,817 $ 202,881 $ 259,152 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 85,365 56,817 202,881 259,152 $ 85,365 $ 56,817 $ 202,881 $ 259,152 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 85,365 $ 56,817 $ 202,881 $ 259,152 Effect of dilutive securities — — — 15,750 Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities $ 85,365 $ 56,817 $ 202,881 $ 274,902 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 210,687 209,982 210,680 209,963 Effect of dilutive securities — — — 14,969 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 210,687 209,982 210,680 224,932 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.41 $ 0.27 $ 0.96 $ 1.23 Per common unit (diluted) $ 0.41 $ 0.27 $ 0.96 $ 1.22 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: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 15,072 14,969 15,072 —

COMMON UNITS

COMMON UNITS	9 Months Ended
	Sep. 30, 2024
Share-Based Payment Arrangement [Abstract]
COMMON UNITS	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 of directors of the Partnership's general partner (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 beginning on November 28, 2023 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 9.8% of the face amount of the preferred units per annum, subject to readjustment on each Readjustment Date; and • second , to the holders of common units. The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 Distributions declared and paid per common unit $ 0.3750 $ 0.4750 $ 1.2250 $ 1.4250 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 nine months ended September 30, 2024. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2024
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Distribution On October 16, 2024, the Board approved a distribution for the three months ended September 30, 2024 of $0.375 per common unit. Distributions will be payable on November 15, 2024 to unitholders of record at the close of business on November 8, 2024. Acquisitions Subsequent to September 30, 2024, the Partnership acquired mineral and royalty interests from various sellers for cash consideration of $12.6 million. These acquisitions were funded with cash from operating activities.

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023 ("2023 Annual Report on Form 10-K"). The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the nine months ended September 30, 2024 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income (loss) and equity in the accompanying unaudited interim consolidated financial statements. The unaudited interim 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 unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting	Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures (Topic 280), which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the amendments provide new segment disclosure requirements for entities with a single reportable segment. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Partnership does not plan to early adopt and expects the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures.
Earnings Per Unit	The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common 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.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2024
Accounting Policies [Abstract]
Schedule of Accounts Receivable	The following table presents information about the Partnership's accounts receivable: September 30, 2024 December 31, 2023 (in thousands) Accounts receivable: Revenues from contracts with customers $ 62,381 $ 77,560 Other 5,738 4,693 Total accounts receivable $ 68,119 $ 82,253

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	9 Months Ended
	Sep. 30, 2024
Extractive Industries [Abstract]
Schedule of Segment Allocation for Business Combinations	The following tables present the working interests each farmout partner will earn within the contract area under the San Augustine farmout agreements: Brent Miller Area Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 64.0 % 32.0 % Azul 20.0 % 10.0 % Former JWM Interest 16.0 % 8.0 % Total 100.0 % 50.0 % Other Areas Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 40.0 % 10.0 % Azul 50.0 % 12.5 % Former JWM Interest 10.0 % 2.5 % Total 100.0 % 25.0 %

COMMODITY DERIVATIVE FINANCIA_2

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value and Classification of Derivative Instruments	The tables below summarize the fair values and classifications 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: September 30, 2024 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 19,178 $ (1,031) $ 18,147 Long-term asset Deferred charges and other long-term assets 3,458 (2,904) 554 Total assets $ 22,636 $ (3,935) $ 18,701 Liabilities: Current liability Commodity derivative liabilities $ 1,031 $ (1,031) $ — Long-term liability Commodity derivative liabilities 5,912 (2,904) 3,008 Total liabilities $ 6,943 $ (3,935) $ 3,008 December 31, 2023 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 41,485 $ (3,212) $ 38,273 Long-term asset Deferred charges and other long-term assets 498 (126) 372 Total assets $ 41,983 $ (3,338) $ 38,645 Liabilities: Current liability Commodity derivative liabilities $ 4,441 $ (3,212) $ 1,229 Long-term liability Commodity derivative liabilities 207 (126) 81 Total liabilities $ 4,648 $ (3,338) $ 1,310
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) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, Derivatives not designated as hedging instruments 2024 2023 2024 2023 (in thousands) Beginning fair value of commodity derivative instruments $ (5,118) $ 51,046 $ 37,335 $ 28,941 Gain (loss) on oil derivative instruments 25,444 (36,013) 988 (21,232) Gain (loss) on natural gas derivative instruments 6,231 9,091 13,850 57,884 Net cash paid (received) on settlements of oil derivative instruments 3,852 (2,659) 9,257 (4,431) Net cash paid (received) on settlements of natural gas derivative instruments (14,716) (21,530) (45,737) (61,227) Net change in fair value of commodity derivative instruments 20,811 (51,111) (21,642) (29,006) Ending fair value of commodity derivative instruments $ 15,693 $ (65) $ 15,693 $ (65)
Schedule of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of September 30, 2024: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2024 Third Quarter 190,000 $ 71.45 $ 67.00 $ 81.00 Fourth Quarter 570,000 71.45 67.00 81.00 2025 First Quarter 555,000 $ 71.22 $ 70.02 $ 73.15 Second Quarter 555,000 71.22 70.02 73.15 Third Quarter 555,000 71.22 70.02 73.15 Fourth Quarter 555,000 71.22 70.02 73.15 2026 First Quarter 120,000 $ 65.85 $ 65.52 $ 66.23 Second Quarter 120,000 65.85 65.52 66.23 Third Quarter 120,000 65.85 65.52 66.23 Fourth Quarter 120,000 65.85 65.52 66.23 The Partnership had the following open derivative contracts for natural gas as of September 30, 2024: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2024 Fourth Quarter 10,580,000 $ 3.55 $ 3.00 $ 3.76 2025 First Quarter 10,800,000 $ 3.36 $ 3.02 $ 3.65 Second Quarter 10,920,000 3.36 3.02 3.65 Third Quarter 11,040,000 3.45 3.34 3.65 Fourth Quarter 11,040,000 3.45 3.34 3.65 2026 First Quarter 7,200,000 $ 3.52 $ 3.50 $ 3.57 Second Quarter 7,280,000 3.52 3.50 3.57 Third Quarter 7,360,000 3.52 3.50 3.57 Fourth Quarter 7,360,000 3.52 3.50 3.57 The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2024: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2026 First Quarter 60,000 $ 67.18 $ 67.00 $ 67.35 Second Quarter 60,000 67.18 67.00 67.35 Third Quarter 60,000 67.18 67.00 67.35 Fourth Quarter 60,000 67.18 67.00 67.35

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2024
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of September 30, 2024 Financial Assets Commodity derivative instruments $ — $ 22,636 $ — $ (3,935) $ 18,701 Financial Liabilities Commodity derivative instruments $ — $ 6,943 $ — $ (3,935) $ 3,008 As of December 31, 2023 Financial Assets Commodity derivative instruments $ — $ 41,983 $ — $ (3,338) $ 38,645 Financial Liabilities Commodity derivative instruments $ — $ 4,648 $ — $ (3,338) $ 1,310

INCENTIVE COMPENSATION (Tables)

INCENTIVE COMPENSATION (Tables)	9 Months Ended
	Sep. 30, 2024
Share-Based Payment Arrangement [Abstract]
Schedule of Incentive Compensation Expense	The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands) Cash—short and long-term incentive plans $ 1,498 $ 1,303 $ 3,883 $ 3,236 Equity-based compensation—restricted common units 1,006 976 2,967 2,872 Equity-based compensation—restricted performance units 621 2,282 2,050 3,968 Board of Directors incentive plan 550 519 1,748 1,572 Total incentive compensation expense $ 3,675 $ 5,080 $ 10,648 $ 11,648

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	9 Months Ended
	Sep. 30, 2024
Earnings Per Share [Abstract]
Schedule of Computation of Basic and Diluted Earnings per Common and Subordinated Unit	The following table sets forth the computation of basic and diluted earnings per common unit: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 92,731 $ 62,067 $ 224,980 $ 274,902 Distributions on Series B cumulative convertible preferred units (7,366) (5,250) (22,099) (15,750) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 85,365 $ 56,817 $ 202,881 $ 259,152 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 85,365 56,817 202,881 259,152 $ 85,365 $ 56,817 $ 202,881 $ 259,152 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 85,365 $ 56,817 $ 202,881 $ 259,152 Effect of dilutive securities — — — 15,750 Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities $ 85,365 $ 56,817 $ 202,881 $ 274,902 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 210,687 209,982 210,680 209,963 Effect of dilutive securities — — — 14,969 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 210,687 209,982 210,680 224,932 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.41 $ 0.27 $ 0.96 $ 1.23 Per common unit (diluted) $ 0.41 $ 0.27 $ 0.96 $ 1.22
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 15,072 14,969 15,072 —

COMMON UNITS (Tables)

COMMON UNITS (Tables)	9 Months Ended
	Sep. 30, 2024
Share-Based Payment Arrangement [Abstract]
Schedule of Distributions made to Limited Partner, by Distribution	The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended September 30, Nine Months Ended September 30, 2024 2023 2024 2023 Distributions declared and paid per common unit $ 0.3750 $ 0.4750 $ 1.2250 $ 1.4250

BUSINESS AND BASIS OF PRESENT_2

BUSINESS AND BASIS OF PRESENTATION (Details)	9 Months Ended
	Sep. 30, 2024 segment state
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20%
Number of operating segments	1
Number of reportable segments	1
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located | state	41

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 68,119	$ 82,253
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	62,381	77,560
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 5,738	$ 4,693

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES - Acquisitions (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Dec. 31, 2023
Asset Acquisition [Line Items]
Aggregate cash consideration	$ 64,180	$ 932
Unproved Oil And Gas Properties
Asset Acquisition [Line Items]
Total consideration	65,200		$ 14,600
Aggregate cash consideration	64,200
Common unit consideration for acquisition	$ 1,000

OIL AND NATURAL GAS PROPERTIE_3

OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details)	1 Months Ended				9 Months Ended		12 Months Ended
	Dec. 31, 2023	May 31, 2021 well	Nov. 30, 2020	May 31, 2020 well	Sep. 30, 2024 USD ($) a well	Sep. 30, 2023 USD ($)	Dec. 31, 2021 well	Dec. 31, 2020 well
Asset Acquisition [Line Items]
Partnership agreement term (in years)		10 years
Impairment of oil and natural gas properties | $					$ 0	$ 0
TEXAS | Asset Exchange
Asset Acquisition [Line Items]
Net acres | a					8,000
MISSISSIPPI | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations
Asset Acquisition [Line Items]
Net acres | a					51,000
Aethon Energy
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year							4	3
Maximum consecutive months suspension	9 months
Total suspension months, maximum	18 months
Suspension period, maximum	48 months
Farmout Agreement | Aethon Energy | San Augustine County, Texas
Asset Acquisition [Line Items]
Net acres | a					25,000
Farmout Agreement | Aethon Energy | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year				15
Farmout Agreement | Pivotal | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year				10
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas
Asset Acquisition [Line Items]
% of Partnership's Working Interest			100%
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Minimum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent			12.50%
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent			25%
Original San Augustine JEA | Aethon Energy | San Augustine County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year		10
Exploratory wells, expected to be drilled		5
Original San Augustine JEA | Aethon Energy | San Augustine County, Texas | Minimum
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year		12
Amended San Augustine JEA | Aethon Energy | San Augustine County, Texas | Minimum
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled per year		12
Exploratory wells, expected to be drilled		9
Oil, productive well, number of wells, net					3
Original Angelina JEA | Aethon Energy | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled				4
Amended Angelina JEA | Aethon Energy | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled fourth program year				15	4

OIL AND NATURAL GAS PROPERTIE_4

OIL AND NATURAL GAS PROPERTIES - Ownership Interest (Details)	1 Months Ended
	May 31, 2021
Partitioned Acreage From XTO
Asset Acquisition [Line Items]
% of Partnership's Working Interest	100%
Partitioned Acreage From XTO | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	50%
Other
Asset Acquisition [Line Items]
% of Partnership's Working Interest	100%
Other | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	25%
Canaan | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	64%
Canaan | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	32%
Canaan | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	40%
Canaan | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	10%
Azul | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	20%
Azul | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	10%
Azul | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	50%
Azul | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	12.50%
Former JWM Interest | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	16%
Former JWM Interest | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	8%
Former JWM Interest | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	10%
Former JWM Interest | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	2.50%

COMMODITY DERIVATIVE FINANCIA_3

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details)	Sep. 30, 2024 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	7

COMMODITY DERIVATIVE FINANCIA_4

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 22,636	$ 41,983
Effect of counterparty netting, assets	(3,935)	(3,338)
Net carrying value on balance sheet, assets	18,701	38,645
Gross fair value, liabilities	6,943	4,648
Effect of counterparty netting, liabilities	(3,935)	(3,338)
Net carrying value on balance sheet, liabilities	3,008	1,310
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	19,178	41,485
Effect of counterparty netting, assets	(1,031)	(3,212)
Net carrying value on balance sheet, assets	18,147	38,273
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	3,458	498
Effect of counterparty netting, assets	(2,904)	(126)
Net carrying value on balance sheet, assets	554	372
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	1,031	4,441
Effect of counterparty netting, liabilities	(1,031)	(3,212)
Net carrying value on balance sheet, liabilities	0	1,229
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	5,912	207
Effect of counterparty netting, liabilities	(2,904)	(126)
Net carrying value on balance sheet, liabilities	$ 3,008	$ 81

COMMODITY DERIVATIVE FINANCIA_5

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ 31,675	$ (26,922)	$ 14,838	$ 36,652
Net cash paid (received) on settlements of derivative instruments			(36,480)	(65,658)
Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	(5,118)	51,046	37,335	28,941
Net change in fair value of commodity derivative instruments	20,811	(51,111)	(21,642)	(29,006)
Ending fair value of commodity derivative instruments	15,693	(65)	15,693	(65)
Derivatives not designated as hedging instruments | Oil Swap Contracts:
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	25,444	(36,013)	988	(21,232)
Net cash paid (received) on settlements of derivative instruments	3,852	(2,659)	9,257	(4,431)
Derivatives not designated as hedging instruments | Natural Gas Swap Contracts:
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	6,231	9,091	13,850	57,884
Net cash paid (received) on settlements of derivative instruments	$ (14,716)	$ (21,530)	$ (45,737)	$ (61,227)

COMMODITY DERIVATIVE FINANCIA_6

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Derivatives not designated as hedging instruments - Swap - Swaps Contract bbl in Thousands, MMBTU in Thousands	1 Months Ended	9 Months Ended
	Nov. 05, 2024 $ / bbl bbl	Sep. 30, 2024 MMBTU $ / bbl $ / MMBTU bbl
Oil Swap Contracts: | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		190
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		71.45
Derivative contract, price range low (in USD per Bbl or MMBtu)		67
Derivative contract, price range high (in USD per Bbl or MMBtu)		81
Oil Swap Contracts: | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		570
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		71.45
Derivative contract, price range low (in USD per Bbl or MMBtu)		67
Derivative contract, price range high (in USD per Bbl or MMBtu)		81
Oil Swap Contracts: | First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		555
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
Oil Swap Contracts: | Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		555
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
Oil Swap Contracts: | Third Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		555
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
Oil Swap Contracts: | Fourth Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		555
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
Oil Swap Contracts: | First Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		65.85
Derivative contract, price range low (in USD per Bbl or MMBtu)		65.52
Derivative contract, price range high (in USD per Bbl or MMBtu)		66.23
Oil Swap Contracts: | First Quarter 2026 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	60
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	67.18
Derivative contract, price range low (in USD per Bbl or MMBtu)	67
Derivative contract, price range high (in USD per Bbl or MMBtu)	67.35
Oil Swap Contracts: | Second Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		65.85
Derivative contract, price range low (in USD per Bbl or MMBtu)		65.52
Derivative contract, price range high (in USD per Bbl or MMBtu)		66.23
Oil Swap Contracts: | Second Quarter 2026 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	60
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	67.18
Derivative contract, price range low (in USD per Bbl or MMBtu)	67
Derivative contract, price range high (in USD per Bbl or MMBtu)	67.35
Oil Swap Contracts: | Third Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		65.85
Derivative contract, price range low (in USD per Bbl or MMBtu)		65.52
Derivative contract, price range high (in USD per Bbl or MMBtu)		66.23
Oil Swap Contracts: | Third Quarter 2026 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	60
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	67.18
Derivative contract, price range low (in USD per Bbl or MMBtu)	67
Derivative contract, price range high (in USD per Bbl or MMBtu)	67.35
Oil Swap Contracts: | Fourth Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		65.85
Derivative contract, price range low (in USD per Bbl or MMBtu)		65.52
Derivative contract, price range high (in USD per Bbl or MMBtu)		66.23
Oil Swap Contracts: | Fourth Quarter 2026 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	60
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	67.18
Derivative contract, price range low (in USD per Bbl or MMBtu)	67
Derivative contract, price range high (in USD per Bbl or MMBtu)	67.35
Natural Gas Swap Contracts: | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,580
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.55
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU		3
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU		3.76
Natural Gas Swap Contracts: | First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,800
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.36
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU		3.02
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU		3.65
Natural Gas Swap Contracts: | Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,920
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.36
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU		3.02
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU		3.65
Natural Gas Swap Contracts: | Third Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		11,040
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.45
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU		3.34
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU		3.65
Natural Gas Swap Contracts: | Fourth Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		11,040
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.45
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU		3.34
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU		3.65
Natural Gas Swap Contracts: | First Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		7,200
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.52
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		3.57
Natural Gas Swap Contracts: | Second Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		7,280
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.52
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		3.57
Natural Gas Swap Contracts: | Third Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		7,360
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.52
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		3.57
Natural Gas Swap Contracts: | Fourth Quarter 2026
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		7,360
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU		3.52
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		3.57

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2024 USD ($) businessCombination	Dec. 31, 2023 USD ($) businessCombination
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 22,636	$ 41,983
Effect of counterparty netting, assets	(3,935)	(3,338)
Net carrying value on balance sheet, assets	18,701	38,645
Gross fair value, liabilities	6,943	4,648
Effect of counterparty netting, liabilities	(3,935)	(3,338)
Net carrying value on balance sheet, liabilities	$ 3,008	$ 1,310
Number of business combinations | businessCombination	0	0
Commodity derivative instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of counterparty netting, assets	$ (3,935)	$ (3,338)
Net carrying value on balance sheet, assets	18,701	38,645
Effect of counterparty netting, liabilities	(3,935)	(3,338)
Net carrying value on balance sheet, liabilities	3,008	1,310
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	0	0
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	22,636	41,983
Gross fair value, liabilities	6,943	4,648
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	$ 0	$ 0

CREDIT FACILITY (Details)

CREDIT FACILITY (Details) - Senior Line of Credit - Revolving Credit Facility	9 Months Ended	12 Months Ended
	Sep. 30, 2024 USD ($)	Dec. 31, 2023 USD ($)	Nov. 30, 2024 USD ($)	Apr. 30, 2024 USD ($)	Oct. 31, 2023 USD ($)	Apr. 30, 2023 USD ($)
Line Of Credit Facility [Line Items]
Maximum borrowing capacity	$ 1,000,000,000
Number of lenders	0.667
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (percent)	10%
Percentage current borrowing base	5%
Borrowing base					$ 580,000,000	$ 550,000,000
Increase limit				$ 375,000,000
Weighted average interest rate (percent)	8.04%	7.36%
Interest payable, term	90 days
Percentage of availability of lenders' commitments, distributions not permitted	10%
Ratio of total debt to EBITDAX, distributions not permitted	3
Aggregate principal balance outstanding	$ 0	$ 0
Unused portion of current borrowing base	$ 375,000,000	$ 375,000,000
Forecast
Line Of Credit Facility [Line Items]
Increase limit			$ 375,000,000
Adjusted Term SOFR
Line Of Credit Facility [Line Items]
Interest rate (percent)	0.10%
Federal Funds Effective Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	0.50%
Adjusted Term Secured Overnight Funds Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1%
Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.375%
Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.50%
Minimum
Line Of Credit Facility [Line Items]
Interest payable, term	90 days
Current ratio	1
Minimum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.50%	1.50%
Minimum | Secured Overnight Financing Rate (SOFR)
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3.5
Maximum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Maximum | Secured Overnight Financing Rate (SOFR)
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.50%	3.50%

INCENTIVE COMPENSATION (Details

INCENTIVE COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Common units | November 2018 Repurchase Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury stock, acquired (in shares)			291,163
Treasury stock, acquired (in dollars per share)			$ 15.28
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash—short and long-term incentive plans	$ 1,498	$ 1,303	$ 3,883	$ 3,236
Incentive compensation expense	3,675	5,080	10,648	11,648
General and administrative expenses | Equity-based compensation—restricted common units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	1,006	976	2,967	2,872
General and administrative expenses | Equity-based compensation—restricted performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	621	2,282	2,050	3,968
General and administrative expenses | Common units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive compensation expense	$ 550	$ 519	$ 1,748	$ 1,572

PREFERRED UNITS (Details)

PREFERRED UNITS (Details) - Series B Cumulative Convertible Preferred Units $ / shares in Units, $ in Thousands	Nov. 28, 2023	Nov. 28, 2017 USD ($) $ / shares shares	Sep. 30, 2024 USD ($)	Dec. 31, 2023 USD ($)
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%	7%
Preferred stock, dividend distribution terms, period of readjustment	2 years
Basis spread on variable rate	5.50%
Distribution rate	2%
Preferred unit conversion ratio		1
Minimum underlying value for conversion trigger		$ 10,000
Redemption maximum		$ 100,000
Redemption price (in dollars per share) | $ / shares		$ 20.39
Period of redemption restriction		90 days
Preferred units, outstanding value			$ 300,478	$ 299,137
Accrued distributions			$ 7,400	$ 6,000
Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares) | shares		14,711,219

EARNINGS PER UNIT - Computation

EARNINGS PER UNIT - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Earnings Per Share [Abstract]
NET INCOME (LOSS)	$ 92,731	$ 62,067	$ 224,980	$ 274,902
Distributions on Series B cumulative convertible preferred units	(7,366)	(5,250)	(22,099)	(15,750)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	85,365	56,817	202,881	259,152
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
Common units	85,365	56,817	202,881	259,152
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	85,365	56,817	202,881	259,152
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders	85,365	56,817	202,881	259,152
Effect of dilutive securities	0	0	0	15,750
Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities	$ 85,365	$ 56,817	$ 202,881	$ 274,902
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic) (in shares)	210,687	209,982	210,680	209,963
Effect of dilutive securities (in shares)	0	0	0	14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities (in shares)	210,687	209,982	210,680	224,932
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.41	$ 0.27	$ 0.96	$ 1.23
Per common unit (diluted) (in dollars per share)	$ 0.41	$ 0.27	$ 0.96	$ 1.22

EARNINGS PER UNIT - Potentially

EARNINGS PER UNIT - Potentially Dilutive Securities Excluded from the Computation of Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Series B cumulative convertible preferred units on an as-converted basis | Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU (in shares)	15,072	14,969	15,072	0

COMMON UNITS - Narrative (Detai

COMMON UNITS - Narrative (Details) - USD ($) $ in Millions			9 Months Ended
	Nov. 28, 2023	Nov. 28, 2017	Sep. 30, 2024	Oct. 30, 2023	Oct. 29, 2023
2023 Unit Repurchase Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount				$ 150
Stock repurchased (in shares)			0
2018 Unit Repurchase Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount					$ 75
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)			15%
Preferred units distribution rate	9.80%	7%

COMMON UNITS - Per Share Distri

COMMON UNITS - Per Share Distributions to Common and Subordinated Unitholders (Details) - Common units - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Class of Stock [Line Items]
Distributions paid per common unit (in dollars per share)	$ 0.3750	$ 0.4750	$ 1.2250	$ 1.4250
Distributions declared per common unit (in dollars per share)	$ 0.3750	$ 0.4750	$ 1.2250	$ 1.4250

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Oct. 16, 2024	Nov. 05, 2024	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023	Dec. 31, 2023
Unproved Oil And Gas Properties
Subsequent Event [Line Items]
Total consideration					$ 65.2		$ 14.6
Subsequent Event | Unproved Oil And Gas Properties
Subsequent Event [Line Items]
Total consideration		$ 12.6
Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)			$ 0.3750	$ 0.4750	$ 1.2250	$ 1.4250
Common units | Subsequent Event
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)	$ 0.375