Black Stone Minerals (BSM) 10-Q 31 Oct 23 2023 Q3 Quarterly report Financial data

Cover

Cover - shares	9 Months Ended
	Sep. 30, 2023	Oct. 27, 2023
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
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	2023
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)		209,990,924
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, 2023	Dec. 31, 2022
CURRENT ASSETS
Cash and cash equivalents	$ 56,030	$ 4,307
Accounts receivable	87,725	135,697
Commodity derivative assets	21,218	31,472
Prepaid expenses and other current assets	1,979	1,905
TOTAL CURRENT ASSETS	166,952	173,381
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $898,768 and $909,344 at September 30, 2023 and December 31, 2022, respectively	3,008,650	3,003,907
Accumulated depreciation, depletion, amortization, and impairment	(1,950,326)	(1,916,919)
Oil and natural gas properties, net	1,058,324	1,086,988
Other property and equipment, net of accumulated depreciation of $13,988 and $13,461 at September 30, 2023 and December 31, 2022, respectively	1,090	1,259
NET PROPERTY AND EQUIPMENT	1,059,414	1,088,247
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,615	9,454
TOTAL ASSETS	1,233,981	1,271,082
CURRENT LIABILITIES
Accounts payable	4,502	6,773
Accrued liabilities	13,597	19,729
Commodity derivative liabilities	14,513	3,243
Other current liabilities	1,173	989
TOTAL CURRENT LIABILITIES	33,785	30,734
LONG–TERM LIABILITIES
Credit facility	0	10,000
Accrued incentive compensation	1,368	1,884
Commodity derivative liabilities	6,770	16
Asset retirement obligations	15,497	15,030
Other long-term liabilities	3,178	3,606
TOTAL LIABILITIES	60,598	61,270
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY
Partners' equity – general partner interest	0	0
TOTAL EQUITY	875,022	911,451
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,233,981	1,271,082
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at September 30, 2023 and December 31, 2022	298,361	298,361
Common units
EQUITY
Partners' equity – common units, 209,986 and 209,407 units outstanding at September 30, 2023 and December 31, 2022, respectively	$ 875,022	$ 911,451

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Unproved properties	$ 898,768	$ 909,344
Accumulated depreciation	$ 13,988	$ 13,461
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common units
Partners' equity - units, outstanding (in shares)	209,986	209,407

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
REVENUE
Revenue from contracts with customers	$ 136,719	$ 221,155	$ 364,723	$ 585,320
Gain (loss) on commodity derivative instruments	(26,922)	(4,726)	36,652	(152,095)
TOTAL REVENUE	109,797	216,429	401,375	433,225
OPERATING (INCOME) EXPENSE
Lease operating expense	2,615	2,896	8,149	9,256
Production costs and ad valorem taxes	16,441	17,856	41,952	51,309
Exploration expense	1,711	10	1,719	192
Depreciation, depletion, and amortization	12,367	12,208	33,935	35,018
General and administrative	14,448	13,044	38,950	39,326
Accretion of asset retirement obligations	254	209	749	616
(Gain) loss on sale of assets, net	(73)	0	(73)	(17)
TOTAL OPERATING EXPENSE	47,763	46,223	125,381	135,700
INCOME (LOSS) FROM OPERATIONS	62,034	170,206	275,994	297,525
OTHER INCOME (EXPENSE)
Interest and investment income	511	20	1,041	22
Interest expense	(621)	(1,693)	(2,080)	(4,264)
Other income (expense)	143	(58)	(53)	(22)
TOTAL OTHER EXPENSE	33	(1,731)	(1,092)	(4,264)
NET INCOME (LOSS)	62,067	168,475	274,902	293,261
Distributions on Series B cumulative convertible preferred units	(5,250)	(5,250)	(15,750)	(15,750)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,817	163,225	259,152	277,511
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
Common units	56,817	163,225	259,152	277,511
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 56,817	$ 163,225	$ 259,152	$ 277,511
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.27	$ 0.78	$ 1.23	$ 1.33
Per common unit (diluted) (in dollars per share)	$ 0.27	$ 0.75	$ 1.22	$ 1.31
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic) (in shares)	209,982	209,402	209,963	209,374
Weighted average common units outstanding (diluted) (in shares)	209,982	224,371	224,932	224,343
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 85,724	$ 80,240	$ 208,184	$ 250,367
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	48,815	137,756	147,857	324,691
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 2,180	$ 3,159	$ 8,682	$ 10,262

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 on an as-converted basis Partners' equity
Beginning balance (in shares) at Dec. 31, 2021		208,666
Beginning balance at Dec. 31, 2021			$ 765,268
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(262)
Repurchases of common units			(2,991)
Restricted units granted, net of forfeitures (in shares)		988
Equity–based compensation			6,659
Distributions			(56,462)
Charges to partners' equity for accrued distribution equivalent rights			(434)
Distributions on Series B cumulative convertible preferred units				$ (5,250)
Net income (loss)			(7,002)
Ending balance (in shares) at Mar. 31, 2022		209,392
Ending balance at Mar. 31, 2022			699,788
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)		7
Equity–based compensation			2,273
Distributions			(83,759)
Charges to partners' equity for accrued distribution equivalent rights			(513)
Distributions on Series B cumulative convertible preferred units				(5,250)
Net income (loss)			131,788
Ending balance (in shares) at Jun. 30, 2022		209,399
Ending balance at Jun. 30, 2022			744,327
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)		3
Equity–based compensation			4,084
Distributions			(87,949)
Charges to partners' equity for accrued distribution equivalent rights			(460)
Distributions on Series B cumulative convertible preferred units				(5,250)
Net income (loss)			168,475
Ending balance (in shares) at Sep. 30, 2022		209,402
Ending balance at Sep. 30, 2022			823,227
Beginning balance (in shares) at Dec. 31, 2022		209,407
Beginning balance at Dec. 31, 2022	$ 911,451		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		$ 875,022

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 274,902	$ 293,261
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	33,935	35,018
Accretion of asset retirement obligations	749	616
Amortization of deferred charges	775	1,041
(Gain) loss on commodity derivative instruments	(36,652)	152,095
Net cash (paid) received on settlement of commodity derivative instruments	65,658	(162,567)
Equity-based compensation	8,412	11,809
(Gain) loss on sale of assets, net	(73)	(17)
Changes in operating assets and liabilities:
Accounts receivable	48,146	(60,345)
Prepaid expenses and other current assets	(74)	(281)
Accounts payable, accrued liabilities, and other	(8,435)	(1,592)
Settlement of asset retirement obligations	(208)	(488)
NET CASH PROVIDED BY OPERATING ACTIVITIES	387,135	268,550
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(932)	(132)
Additions to oil and natural gas properties	(3,720)	(11,811)
Additions to oil and natural gas properties leasehold costs	(9)	(32)
Purchases of other property and equipment	(358)	(50)
Proceeds from the sale of oil and natural gas properties	73	17
Proceeds from farmouts of oil and natural gas properties	0	11,331
NET CASH USED IN INVESTING ACTIVITIES	(4,946)	(677)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility	64,000	237,000
Repayments under credit facility	(74,000)	(266,000)
Debt issuance costs and other	(142)	0
NET CASH USED IN FINANCING ACTIVITIES	(330,466)	(275,911)
NET CHANGE IN CASH AND CASH EQUIVALENTS	51,723	(8,038)
CASH AND CASH EQUIVALENTS – beginning of the period	4,307	8,876
CASH AND CASH EQUIVALENTS – end of the period	56,030	838
SUPPLEMENTAL DISCLOSURE
Interest paid	1,330	3,203
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(299,078)	(228,170)
Repurchases of common units	(5,496)	(2,991)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (15,750)	$ (15,750)

BUSINESS AND BASIS OF PRESENTAT

BUSINESS AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS AND BASIS OF PRESENTATION	BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM." Basis of Presentation The accompanying 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, 2022 ("2022 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, 2023 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. 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, 2023
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 2022 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, 2023. Accounts Receivable The following table presents information about the Partnership's accounts receivable: September 30, 2023 December 31, 2022 (in thousands) Accounts receivable: Revenues from contracts with customers $ 80,018 $ 129,078 Other 7,707 6,619 Total accounts receivable $ 87,725 $ 135,697

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	9 Months Ended
	Sep. 30, 2023
Extractive Industries [Abstract]
OIL AND NATURAL GAS PROPERTIES	OIL AND NATURAL GAS PROPERTIES Divestitures The Partnership had no material divestiture activity during 2022 or the nine months ended September 30, 2023. 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. In the third quarter of 2023, the Partnership acquired mineral and royalty acreage in East Texas from various sellers for aggregate cash consideration of $0.9 million. These acquisitions were considered asset acquisitions and were funded with cash from operating activities. The Partnership had no material acquisition activity during the nine months ended September 30, 2022. 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. San Augustine Farmout In May 2021, BSM and Aethon Energy ("Aethon") entered into an agreement to develop certain of the Partnership's undeveloped acreage in San Augustine County. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which began in the third quarter of 2021, 10 wells to be drilled in the second and third program years, and, thereafter, a minimum of 12 wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County discussed below. In May 2021, the Partnership entered into a farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). In April 2022, the Partnership amended the Canaan Farmout and entered into a farmout agreement (the "JWM Farmout") with JWM Oil & Gas LLC ("JWM"). These agreements cover all of the Partnership's share of working interests under active development by Aethon in San Augustine County, Texas and continue for a 10 year period, unless earlier terminated in accordance with the terms of the agreements. Canaan, Azul, and JWM will each earn a percentage of the Partnership's working interest in wells drilled and operated by Aethon within the contract area subject to the agreements. Canaan, Azul, and JWM are obligated to fund the development of wells drilled by Aethon in the initial program year, and thereafter, have certain rights and options to continue funding the Partnership's working interest for the duration of each farmout agreement. The Partnership will receive an overriding royalty interest ("ORRI") before payout and an increased ORRI after payout on all wells drilled under the farmout agreements. As of September 30, 2023, 17 wells have been spud by Aethon in the contract area subject to the Canaan, Azul, and JWM Farmouts. The following tables present the working interests each farmout partner will earn within the contract area under the San Augustine farmout agreements: Brent Miller Area Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 64.0 % 32.0 % Azul 20.0 % 10.0 % JWM 16.0 % 8.0 % Total 100.0 % 50.0 % Other Areas Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8ths basis Canaan 40.0 % 10.0 % Azul 50.0 % 12.5 % JWM 10.0 % 2.5 % Total 100.0 % 25.0 % Angelina Farmout In May 2020, the Partnership entered into a development agreement with Aethon to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, 10 wells to be drilled in the second program year, and, beginning with the third program year, 15 wells per year beginning thereafter. In November 2020, the Partnership entered into a farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal 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. As of September 30, 2023, 45 wells have been spud by Aethon in the contract area subject to the Pivotal Farmout. 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, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS	COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes. As of September 30, 2023, 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, 2023 and December 31, 2022. See Note 5 - Fair Value Measurements for further discussion. The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2023, the Partnership had seven counterparties, all of which are rated Baa1 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, 2023 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 26,896 $ (5,678) $ 21,218 Long-term asset Deferred charges and other long-term assets 5 (5) — Total assets $ 26,901 $ (5,683) $ 21,218 Liabilities: Current liability Commodity derivative liabilities $ 20,191 $ (5,678) $ 14,513 Long-term liability Commodity derivative liabilities 6,775 (5) 6,770 Total liabilities $ 26,966 $ (5,683) $ 21,283 December 31, 2022 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 41,648 $ (10,176) $ 31,472 Long-term asset Deferred charges and other long-term assets 797 (69) 728 Total assets $ 42,445 $ (10,245) $ 32,200 Liabilities: Current liability Commodity derivative liabilities $ 13,419 $ (10,176) $ 3,243 Long-term liability Commodity derivative liabilities 85 (69) 16 Total liabilities $ 13,504 $ (10,245) $ 3,259 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, Derivatives not designated as hedging instruments 2023 2022 2023 2022 (in thousands) Beginning fair value of commodity derivative instruments $ 51,046 $ (107,218) $ 28,941 $ (53,545) Gain (loss) on oil derivative instruments (36,013) 32,022 (21,232) (33,096) Gain (loss) on natural gas derivative instruments 9,091 (36,748) 57,884 (118,999) Net cash paid (received) on settlements of oil derivative instruments (2,659) 23,275 (4,431) 65,512 Net cash paid (received) on settlements of natural gas derivative instruments (21,530) 45,596 (61,227) 97,055 Net change in fair value of commodity derivative instruments (51,111) 64,145 (29,006) 10,472 Ending fair value of commodity derivative instruments $ (65) $ (43,073) $ (65) $ (43,073) The Partnership had the following open derivative contracts for oil as of September 30, 2023: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2023 Third Quarter 180,000 $ 80.80 $ 73.00 $ 89.50 Fourth Quarter 540,000 80.80 73.00 89.50 2024 First Quarter 450,000 $ 68.98 $ 67.00 $ 72.82 Second Quarter 450,000 68.98 67.00 72.82 Third Quarter 450,000 68.98 67.00 72.82 Fourth Quarter 450,000 68.98 67.00 72.82 The Partnership had the following open derivative contracts for natural gas as of September 30, 2023: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2023 Fourth Quarter 8,280,000 5.15 3.28 6.59 2024 First Quarter 10,010,000 $ 3.57 $ 3.48 $ 3.76 Second Quarter 10,010,000 3.57 3.48 3.76 Third Quarter 10,120,000 3.57 3.48 3.76 Fourth Quarter 10,120,000 3.57 3.48 3.76 The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2023: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2024 First Quarter 120,000 $ 80.71 $ 80.35 $ 81.00 Second Quarter 120,000 80.71 80.35 81.00 Third Quarter 120,000 80.71 80.35 81.00 Fourth Quarter 120,000 80.71 80.35 81.00

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement , establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 —Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 —Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 —Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. 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, 2023 and December 31, 2022 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 4 - Commodity Derivative Financial Instruments for further discussion. The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of September 30, 2023 Financial Assets Commodity derivative instruments $ — $ 26,901 $ — $ (5,683) $ 21,218 Financial Liabilities Commodity derivative instruments $ — $ 26,966 $ — $ (5,683) $ 21,283 As of December 31, 2022 Financial Assets Commodity derivative instruments $ — $ 42,445 $ — $ (10,245) $ 32,200 Financial Liabilities Commodity derivative instruments $ — $ 13,504 $ — $ (10,245) $ 3,259 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership had no business combinations for the nine months ended September 30, 2023 or the year ended December 31, 2022. 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. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty, particularly in the current volatile market, and cannot be determined with precision. Changes to these estimates, particularly related to economic reserves, future commodity prices, and timing of future production could result in additional impairment charges in the future. There were no significant changes in valuation techniques or related inputs as of September 30, 2023 or December 31, 2022. There were no assets measured at fair value on a non-recurring basis for the nine months ended September 30, 2023 or the year ended December 31, 2022.

CREDIT FACILITY

CREDIT FACILITY	9 Months Ended
	Sep. 30, 2023
Debt Disclosure [Abstract]
CREDIT FACILITY	CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base. In October 2022, the Partnership revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and the Partnership elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million. The October 2023 borrowing base redetermination increased the borrowing base to $580.0 million with no change to the cash commitments. The next semi-annual redetermination is scheduled for April 2024. In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR"). Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50%, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or Adjusted Term SOFR, in each case, plus the applicable margin. As of December 31, 2022 and September 30, 2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base. The weighted-average interest rate of the Credit Facility was 7.33% during the nine months ended September 30, 2023 and 6.92% as of December 31, 2022. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. 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, 2023, the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was zero and $10.0 million at September 30, 2023 and December 31, 2022, respectively. The unused portion of the available borrowings under the Credit Facility were $375.0 million and $365.0 million at September 30, 2023 and December 31, 2022, respectively.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2023
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been recorded. Litigation

INCENTIVE COMPENSATION

INCENTIVE COMPENSATION	9 Months Ended
	Sep. 30, 2023
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, 2023 2022 2023 2022 (in thousands) Cash—short and long-term incentive plans $ 1,303 $ 1,422 $ 3,236 $ 4,381 Equity-based compensation—restricted common units 976 1,054 2,872 3,030 Equity-based compensation—restricted performance units 2,282 2,949 3,968 7,186 Board of Directors incentive plan 519 531 1,572 1,593 Total incentive compensation expense $ 5,080 $ 5,956 $ 11,648 $ 16,190 For the nine months ended September 30, 2023, the Partnership repurchased 357,761 common units at an average price of $15.36 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 shares to cover the employee's tax liability.

PREFERRED UNITS

PREFERRED UNITS	9 Months Ended
	Sep. 30, 2023
Equity [Abstract]
PREFERRED UNITS	PREFERRED UNITS Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million. The Series B cumulative convertible preferred units are entitled to an annual distribution of 7.0%, payable on a quarterly basis in arrears; provided that the distribution rate will be adjusted as follows: commencing on November 28, 2023 and readjusting every two years thereafter (each, a "Readjustment Date"), the rate will equal 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 Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 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 November 28, 2023 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value. Thereafter, the Partnership may redeem the Series B cumulative convertible preferred units at par within a 90 day period on each second anniversary following November 28, 2023. The Series B cumulative convertible preferred units had a carrying value of $298.4 million, including accrued distributions of $5.3 million, as of September 30, 2023 and December 31, 2022. 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, 2023
Earnings Per Share [Abstract]
EARNINGS PER UNIT	EARNINGS PER UNIT The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Partnership assesses the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. The following table sets forth the computation of basic and diluted earnings per common unit: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 62,067 $ 168,475 $ 274,902 $ 293,261 Distributions on Series B cumulative convertible preferred units (5,250) (5,250) (15,750) (15,750) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 56,817 $ 163,225 $ 259,152 $ 277,511 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 56,817 163,225 259,152 277,511 $ 56,817 $ 163,225 $ 259,152 $ 277,511 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 56,817 $ 163,225 $ 259,152 $ 277,511 Effect of dilutive securities — 5,250 15,750 15,750 Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 56,817 $ 168,475 $ 274,902 $ 293,261 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 209,982 209,402 209,963 209,374 Effect of dilutive securities — 14,969 14,969 14,969 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 209,982 224,371 224,932 224,343 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.27 $ 0.78 $ 1.23 $ 1.33 Per common unit (diluted) $ 0.27 $ 0.75 $ 1.22 $ 1.31 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, 2023 2022 2023 2022 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,969 — — —

COMMON UNITS

COMMON UNITS	9 Months Ended
	Sep. 30, 2023
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, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control, may not vote on any matter. The partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments; and • second , to the holders of common units. The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 Distributions declared and paid per common unit $ 0.4750 $ 0.4200 $ 1.4250 $ 1.0900

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2023
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS    On October 18, 2023, the Board approved a distribution for the three months ended September 30, 2023 of $0.475 per common unit. Distributions will be payable on November 16, 2023 to unitholders of record at the close of business on November 9, 2023.On October 30, 2023, the Board authorized a $150 million unit repurchase program, terminating its existing $75 million program authorized in 2018. The unit repurchase program authorized 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. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when the Partnership might otherwise be precluded from doing so under applicable laws. The repurchase program does not obligate the Partnership to acquire any particular number of common units and may be modified or suspended at any time and could be terminated prior to completion. The Partnership will periodically report the number of common units repurchased. The program will be funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units will be canceled.

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2023
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, 2022 ("2022 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, 2023 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. 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.
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, 2023
Accounting Policies [Abstract]
Schedule of Accounts Receivable	The following table presents information about the Partnership's accounts receivable: September 30, 2023 December 31, 2022 (in thousands) Accounts receivable: Revenues from contracts with customers $ 80,018 $ 129,078 Other 7,707 6,619 Total accounts receivable $ 87,725 $ 135,697

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	9 Months Ended
	Sep. 30, 2023
Extractive Industries [Abstract]
Business Combination, Segment Allocation	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 % JWM 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 % JWM 10.0 % 2.5 % Total 100.0 % 25.0 %

COMMODITY DERIVATIVE FINANCIA_2

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary 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, 2023 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 26,896 $ (5,678) $ 21,218 Long-term asset Deferred charges and other long-term assets 5 (5) — Total assets $ 26,901 $ (5,683) $ 21,218 Liabilities: Current liability Commodity derivative liabilities $ 20,191 $ (5,678) $ 14,513 Long-term liability Commodity derivative liabilities 6,775 (5) 6,770 Total liabilities $ 26,966 $ (5,683) $ 21,283 December 31, 2022 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 41,648 $ (10,176) $ 31,472 Long-term asset Deferred charges and other long-term assets 797 (69) 728 Total assets $ 42,445 $ (10,245) $ 32,200 Liabilities: Current liability Commodity derivative liabilities $ 13,419 $ (10,176) $ 3,243 Long-term liability Commodity derivative liabilities 85 (69) 16 Total liabilities $ 13,504 $ (10,245) $ 3,259
Changes in Fair Value of Company's Commodity Derivative Instruments	Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, Derivatives not designated as hedging instruments 2023 2022 2023 2022 (in thousands) Beginning fair value of commodity derivative instruments $ 51,046 $ (107,218) $ 28,941 $ (53,545) Gain (loss) on oil derivative instruments (36,013) 32,022 (21,232) (33,096) Gain (loss) on natural gas derivative instruments 9,091 (36,748) 57,884 (118,999) Net cash paid (received) on settlements of oil derivative instruments (2,659) 23,275 (4,431) 65,512 Net cash paid (received) on settlements of natural gas derivative instruments (21,530) 45,596 (61,227) 97,055 Net change in fair value of commodity derivative instruments (51,111) 64,145 (29,006) 10,472 Ending fair value of commodity derivative instruments $ (65) $ (43,073) $ (65) $ (43,073)
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of September 30, 2023: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2023 Third Quarter 180,000 $ 80.80 $ 73.00 $ 89.50 Fourth Quarter 540,000 80.80 73.00 89.50 2024 First Quarter 450,000 $ 68.98 $ 67.00 $ 72.82 Second Quarter 450,000 68.98 67.00 72.82 Third Quarter 450,000 68.98 67.00 72.82 Fourth Quarter 450,000 68.98 67.00 72.82 The Partnership had the following open derivative contracts for natural gas as of September 30, 2023: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2023 Fourth Quarter 8,280,000 5.15 3.28 6.59 2024 First Quarter 10,010,000 $ 3.57 $ 3.48 $ 3.76 Second Quarter 10,010,000 3.57 3.48 3.76 Third Quarter 10,120,000 3.57 3.48 3.76 Fourth Quarter 10,120,000 3.57 3.48 3.76 The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2023: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2024 First Quarter 120,000 $ 80.71 $ 80.35 $ 81.00 Second Quarter 120,000 80.71 80.35 81.00 Third Quarter 120,000 80.71 80.35 81.00 Fourth Quarter 120,000 80.71 80.35 81.00

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of September 30, 2023 Financial Assets Commodity derivative instruments $ — $ 26,901 $ — $ (5,683) $ 21,218 Financial Liabilities Commodity derivative instruments $ — $ 26,966 $ — $ (5,683) $ 21,283 As of December 31, 2022 Financial Assets Commodity derivative instruments $ — $ 42,445 $ — $ (10,245) $ 32,200 Financial Liabilities Commodity derivative instruments $ — $ 13,504 $ — $ (10,245) $ 3,259

INCENTIVE COMPENSATION (Tables)

INCENTIVE COMPENSATION (Tables)	9 Months Ended
	Sep. 30, 2023
Share-Based Payment Arrangement [Abstract]
Summary 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, 2023 2022 2023 2022 (in thousands) Cash—short and long-term incentive plans $ 1,303 $ 1,422 $ 3,236 $ 4,381 Equity-based compensation—restricted common units 976 1,054 2,872 3,030 Equity-based compensation—restricted performance units 2,282 2,949 3,968 7,186 Board of Directors incentive plan 519 531 1,572 1,593 Total incentive compensation expense $ 5,080 $ 5,956 $ 11,648 $ 16,190

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	9 Months Ended
	Sep. 30, 2023
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings per Common and Subordinated Unit	The following table sets forth the computation of basic and diluted earnings per common unit: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 62,067 $ 168,475 $ 274,902 $ 293,261 Distributions on Series B cumulative convertible preferred units (5,250) (5,250) (15,750) (15,750) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 56,817 $ 163,225 $ 259,152 $ 277,511 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 56,817 163,225 259,152 277,511 $ 56,817 $ 163,225 $ 259,152 $ 277,511 NUMERATOR: Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 56,817 $ 163,225 $ 259,152 $ 277,511 Effect of dilutive securities — 5,250 15,750 15,750 Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 56,817 $ 168,475 $ 274,902 $ 293,261 DENOMINATOR: Denominator for basic EPU - weighted average common units outstanding (basic) 209,982 209,402 209,963 209,374 Effect of dilutive securities — 14,969 14,969 14,969 Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 209,982 224,371 224,932 224,343 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.27 $ 0.78 $ 1.23 $ 1.33 Per common unit (diluted) $ 0.27 $ 0.75 $ 1.22 $ 1.31
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, 2023 2022 2023 2022 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,969 — — —

COMMON UNITS (Tables)

COMMON UNITS (Tables)	9 Months Ended
	Sep. 30, 2023
Share-Based Payment Arrangement [Abstract]
Distributions Made to Limited Partner, by Distribution	The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 Distributions declared and paid per common unit $ 0.4750 $ 0.4200 $ 1.4250 $ 1.0900

BUSINESS AND BASIS OF PRESENT_2

BUSINESS AND BASIS OF PRESENTATION - Narrative (Details)	9 Months Ended
	Sep. 30, 2023 state segment
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20%
Number of operating segments	1
Number of reportable segments	1
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located | state	41

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 87,725	$ 135,697
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	80,018	129,078
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 7,707	$ 6,619

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES - Acquisitions (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2023	Sep. 30, 2022
Asset Acquisition [Line Items]
Aggregate cash consideration		$ 932	$ 132
Mineral and Royalty Acreage
Asset Acquisition [Line Items]
Aggregate cash consideration	$ 900

OIL AND NATURAL GAS PROPERTIE_3

OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details)	1 Months Ended		3 Months Ended				9 Months Ended		12 Months Ended
	May 31, 2021	Nov. 30, 2020	Sep. 30, 2023 USD ($) well	Sep. 30, 2022 USD ($)	Sep. 30, 2021 well	Sep. 30, 2020 well	Sep. 30, 2023 USD ($) well	Sep. 30, 2022 USD ($)	Dec. 31, 2022 well	Dec. 31, 2021 well
Asset Acquisition [Line Items]
Partnership agreement term (in years)	10 years
Impairment of oil and natural gas properties | $			$ 0	$ 0			$ 0	$ 0
Farmout Agreement | Aethon Energy | San Augustine County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled initial program year					5
Exploratory wells, expected to be drilled					10
Farmout Agreement | Aethon Energy | San Augustine County, Texas | Minimum
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled					12
Farmout Agreement | Aethon Energy | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled						4
Exploratory wells, expected to be drilled per year									15
Farmout Agreement | Azul-SA, LLC And Canaan Resource Partners | San Augustine County, Texas
Asset Acquisition [Line Items]
Oil, productive well, number of wells, net			17				17
Farmout Agreement | Pivotal | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled										10
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas
Asset Acquisition [Line Items]
Oil, productive well, number of wells, net			45				45
% 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%

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%
Maximum % on an 8/8ths basis	50%
Other
Asset Acquisition [Line Items]
% of Partnership's Working Interest	100%
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%
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%
JWM | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	16%
JWM | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	8%
JWM | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	10%
JWM | 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, 2023 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	7

COMMODITY DERIVATIVE FINANCIA_4

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 26,901	$ 42,445
Effect of counterparty netting, assets	(5,683)	(10,245)
Total net carrying value on balance sheet, assets	21,218	32,200
Gross fair value, liabilities	26,966	13,504
Effect of counterparty netting, liabilities	(5,683)	(10,245)
Total net carrying value on balance sheet, liabilities	21,283	3,259
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	26,896	41,648
Effect of counterparty netting, assets	(5,678)	(10,176)
Total net carrying value on balance sheet, assets	21,218	31,472
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	5	797
Effect of counterparty netting, assets	(5)	(69)
Total net carrying value on balance sheet, assets	0	728
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	20,191	13,419
Effect of counterparty netting, liabilities	(5,678)	(10,176)
Total net carrying value on balance sheet, liabilities	14,513	3,243
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	6,775	85
Effect of counterparty netting, liabilities	(5)	(69)
Total net carrying value on balance sheet, liabilities	$ 6,770	$ 16

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, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (26,922)	$ (4,726)	$ 36,652	$ (152,095)
Net cash paid (received) on settlements of derivative instruments			(65,658)	162,567
Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	51,046	(107,218)	28,941	(53,545)
Net change in fair value of commodity derivative instruments	(51,111)	64,145	(29,006)	10,472
Ending fair value of commodity derivative instruments	(65)	(43,073)	(65)	(43,073)
Derivatives not designated as hedging instruments | Oil Swap Contracts:
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(36,013)	32,022	(21,232)	(33,096)
Net cash paid (received) on settlements of derivative instruments	(2,659)	23,275	(4,431)	65,512
Derivatives not designated as hedging instruments | Natural gas and natural gas liquids sales
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	9,091	(36,748)	57,884	(118,999)
Net cash paid (received) on settlements of derivative instruments	$ (21,530)	$ 45,596	$ (61,227)	$ 97,055

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
	Oct. 31, 2023 MMBTU $ / MMBTU	Sep. 30, 2023 MMBTU $ / MMBTU $ / bbl bbl
Oil Swap Contracts: | Third Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		180
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		80.80
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		73
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		89.50
Oil Swap Contracts: | Fourth Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		540
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		80.80
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		73
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		89.50
Oil Swap Contracts: | First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		450
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		68.98
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		67
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		72.82
Oil Swap Contracts: | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		450
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		68.98
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		67
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		72.82
Oil Swap Contracts: | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		450
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		68.98
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		67
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		72.82
Oil Swap Contracts: | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl		450
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl		68.98
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl		67
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl		72.82
Natural gas and natural gas liquids sales | Fourth Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		8,280
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		5.15
Derivative contract, price range low (in USD per Bbl or MMBtu)		3.28
Derivative contract, price range high (in USD per Bbl or MMBtu)		6.59
Natural gas and natural gas liquids sales | First Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,010
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		3.57
Derivative contract, price range low (in USD per Bbl or MMBtu)		3.48
Derivative contract, price range high (in USD per Bbl or MMBtu)		3.76
Natural gas and natural gas liquids sales | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,010
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		3.57
Derivative contract, price range low (in USD per Bbl or MMBtu)		3.48
Derivative contract, price range high (in USD per Bbl or MMBtu)		3.76
Natural gas and natural gas liquids sales | Third Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		3.57
Derivative contract, price range low (in USD per Bbl or MMBtu)		3.48
Derivative contract, price range high (in USD per Bbl or MMBtu)		3.76
Natural gas and natural gas liquids sales | Fourth Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		10,120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		3.57
Derivative contract, price range low (in USD per Bbl or MMBtu)		3.48
Derivative contract, price range high (in USD per Bbl or MMBtu)		3.76
Oil and condensate sales | First Quarter 2024 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	80.71
Derivative contract, price range low (in USD per Bbl or MMBtu)	80.35
Derivative contract, price range high (in USD per Bbl or MMBtu)	81
Oil and condensate sales | Second Quarter 2024 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	80.71
Derivative contract, price range low (in USD per Bbl or MMBtu)	80.35
Derivative contract, price range high (in USD per Bbl or MMBtu)	81
Oil and condensate sales | Third Quarter 2024 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	80.71
Derivative contract, price range low (in USD per Bbl or MMBtu)	80.35
Derivative contract, price range high (in USD per Bbl or MMBtu)	81
Oil and condensate sales | Fourth Quarter 2024 | Subsequent Event
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	120
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	80.71
Derivative contract, price range low (in USD per Bbl or MMBtu)	80.35
Derivative contract, price range high (in USD per Bbl or MMBtu)	81

FAIR VALUE MEASUREMENTS - Sched

FAIR VALUE MEASUREMENTS - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 26,901	$ 42,445
Effect of counterparty netting, assets	(5,683)	(10,245)
Total net carrying value on balance sheet, assets	21,218	32,200
Gross fair value, liabilities	26,966	13,504
Effect of counterparty netting, liabilities	(5,683)	(10,245)
Total net carrying value on balance sheet, liabilities	21,283	3,259
Commodity derivative instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of counterparty netting, assets	(5,683)	(10,245)
Total net carrying value on balance sheet, assets	21,218	32,200
Effect of counterparty netting, liabilities	(5,683)	(10,245)
Total net carrying value on balance sheet, liabilities	21,283	3,259
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	0	0
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	26,901	42,445
Gross fair value, liabilities	26,966	13,504
Commodity derivative instruments | Fair Value Measurements, Recurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	$ 0	$ 0

CREDIT FACILITY (Details)

CREDIT FACILITY (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($) lender	Dec. 31, 2022 USD ($)	Oct. 31, 2023 USD ($)	Oct. 30, 2023 USD ($)	Apr. 30, 2023 USD ($)	Oct. 31, 2022 USD ($)
Line Of Credit Facility [Line Items]
Number of lenders | lender	0.667
Percentage current borrowing base	5%
Current ratio	1
Credit facility	$ 0	$ 10,000
Senior Line of Credit | Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity	$ 1,000,000
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (percent)	10%
Borrowing base					$ 550,000	$ 550,000
Increase limit	$ 400,000				$ 375,000	$ 375,000
Weighted average interest rate (percent)	7.33%	6.92%
Interest payable, term	90 days
Borrowing base threshold (percent)	50%
Percentage of availability of lenders' commitments, distributions not permitted	10%
Ratio of total debt to EBITDAX, distributions not permitted	3
Credit facility	$ 0	$ 10,000
Unused portion of current borrowing base	$ 375,000	$ 365,000
Senior Line of Credit | Revolving Credit Facility | Subsequent Event
Line Of Credit Facility [Line Items]
Borrowing base			$ 580,000
Increase limit				$ 375,000
Senior Line of Credit | Revolving Credit Facility | Federal Funds Effective Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	0.50%
Senior Line of Credit | Revolving Credit Facility | Adjusted Term Secured Overnight Funds Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.375%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.50%
Senior Line of Credit | Revolving Credit Facility | Minimum
Line Of Credit Facility [Line Items]
Interest payable, term	90 days
Current ratio	1
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.50%	1.50%
Senior Line of Credit | Revolving Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR)
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Senior Line of Credit | Revolving Credit Facility | Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3.5
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Senior Line of Credit | Revolving Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR)
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.50%	3.50%

INCENTIVE COMPENSATION - Summar

INCENTIVE COMPENSATION - Summary of Incentive Compensation Expense (Details) $ / shares in Units, MMBoe in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($) commonUnit	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) MMBoe commonUnit $ / shares shares	Sep. 30, 2022 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation			$ 0
Number of common units receivable | commonUnit	1		1
Mboe per day | MMBoe			42
Current ratio			1
Common units | November 2018 Repurchase Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury stock, acquired (in shares) | shares			357,761
Treasury stock, acquired (in USD per share) | $ / shares			$ 15.36
Performance Cash Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation			$ 5,700
Performance Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation			$ 14,900
Grant of stock units (in shares) | shares			1,244,945
Weighted-average grant date fair value (in USD per share) | $ / shares			$ 11.93
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash—short and long-term incentive plans	$ 1,303	$ 1,422	$ 3,236	$ 4,381
Incentive compensation expense	5,080	5,956	11,648	16,190
General and administrative expenses | Equity-based compensation—restricted common units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	976	1,054	2,872	3,030
General and administrative expenses | Equity-based compensation—restricted performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	2,282	2,949	3,968	7,186
General and administrative expenses | Common units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive compensation expense	$ 519	$ 531	$ 1,572	$ 1,593

PREFERRED UNITS (Details)

PREFERRED UNITS (Details) $ / shares in Units, $ in Thousands			9 Months Ended
	Nov. 28, 2023 USD ($) $ / shares	Nov. 28, 2017 USD ($) $ / shares shares	Sep. 30, 2023 USD ($)	Dec. 31, 2022 USD ($)
Forecast
Class of Stock [Line Items]
Redemption maximum	$ 100,000
Redemption price (in USD per share) | $ / shares	$ 21.41
Period of redemption restriction	90 days
Redemption price of preferred stock (percentage)	105%
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Shares, price per share (in dollars per share) | $ / shares		$ 20.3926
Proceeds from issuance of convertible preferred stock		$ 300,000
Preferred units distribution rate		7%	7%
Preferred unit conversion ratio		1
Minimum underlying value for conversion trigger		$ 10,000
Preferred units, outstanding value			$ 298,361	$ 298,361
Accrued distributions			$ 5,300	$ 5,300
Series B Cumulative Convertible Preferred Units | Forecast
Class of Stock [Line Items]
Distribution rate	2%
Series B Cumulative Convertible Preferred Units | Forecast | US Treasury (UST) Interest Rate
Class of Stock [Line Items]
Basis spread on variable rate	5.50%
Series B Cumulative Convertible Preferred Units | 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, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings Per Share [Abstract]
NET INCOME (LOSS)	$ 62,067	$ 168,475	$ 274,902	$ 293,261
Distributions on Series B cumulative convertible preferred units	(5,250)	(5,250)	(15,750)	(15,750)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,817	163,225	259,152	277,511
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
Common units	56,817	163,225	259,152	277,511
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,817	163,225	259,152	277,511
NUMERATOR:
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,817	163,225	259,152	277,511
Effect of dilutive securities	0	5,250	15,750	15,750
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$ 56,817	$ 168,475	$ 274,902	$ 293,261
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic) (in shares)	209,982	209,402	209,963	209,374
Effect of dilutive securities (in shares)	0	14,969	14,969	14,969
Denominator for diluted EPU - weighted average common units outstanding after the effect of dilutive securities (in shares)	209,982	224,371	224,932	224,343
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.27	$ 0.78	$ 1.23	$ 1.33
Per common unit (diluted) (in dollars per share)	$ 0.27	$ 0.75	$ 1.22	$ 1.31

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, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
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)	14,969	0	0	0

COMMON UNITS - Narrative (Detai

COMMON UNITS - Narrative (Details) - Series B Cumulative Convertible Preferred Units		9 Months Ended
	Nov. 28, 2017	Sep. 30, 2023
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)		15%
Preferred units distribution rate	7%	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, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Class of Stock [Line Items]
Distributions paid per common unit (in dollars per share)	$ 0.4750	$ 0.4200	$ 1.4250	$ 1.0900
Distributions declared per common unit (in dollars per share)	$ 0.4750	$ 0.4200	$ 1.4250	$ 1.0900

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
	Oct. 18, 2023	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Oct. 30, 2023	Oct. 29, 2023
Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)		$ 0.4750	$ 0.4200	$ 1.4250	$ 1.0900
Subsequent Event | 2023 Unit Repurchase Plan
Subsequent Event [Line Items]
Stock repurchase program, authorized amount						$ 150
Subsequent Event | 2018 Unit Repurchase Plan
Subsequent Event [Line Items]
Stock repurchase program, authorized amount							$ 75
Subsequent Event | Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)	$ 0.475