10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2024

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period _______________ to _______________

Commission File Number: 001-37362

Black Stone Minerals, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware		47-1846692
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 2020
Houston,	Texas	77002
(Address of principal executive offices)		(Zip code)

(713)	445-3200
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	BSM	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. 

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of May 3, 2024, there were 210,702,620 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

TABLE OF CONTENTS

 

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statements of Equity	3
	Consolidated Statements of Cash Flows	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 5.	Other Information	31
Item 6.	Exhibits	32
	Signatures	33

ii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements 

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)

	March 31, 2024		December 31, 2023
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	40,456	$	70,282
Accounts receivable	72,428		82,253
Commodity derivative assets	30,741		38,273
Prepaid expenses and other current assets	2,540		2,319
TOTAL CURRENT ASSETS	146,165		193,127
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $913,031 and $890,338 at March 31, 2024 and December 31, 2023, respectively	3,049,455		3,026,394
Accumulated depreciation, depletion, amortization, and impairment	(1,972,524)		(1,961,899)
Oil and natural gas properties, net	1,076,931		1,064,495
Other property and equipment, net of accumulated depreciation of $14,270 and $14,163 at March 31, 2024 and December 31, 2023, respectively	938		1,007
NET PROPERTY AND EQUIPMENT	1,077,869		1,065,502
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,641		8,255
TOTAL ASSETS	$	1,231,675	$	1,266,884
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	5,844	$	6,270
Accrued liabilities	7,380		17,003
Commodity derivative liabilities	12,782		1,229
Other current liabilities	1,374		1,334
TOTAL CURRENT LIABILITIES	27,380		25,836
LONG–TERM LIABILITIES
Accrued incentive compensation	802		1,699
Commodity derivative liabilities	5,858		81
Asset retirement obligations	19,078		19,030
Other long-term liabilities	2,755		2,893
TOTAL LIABILITIES	55,873		49,539
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2024 and December 31, 2023	300,478		299,137
EQUITY
Partners' equity – general partner interest	—		—
Partners' equity – common units, 210,656 and 209,991 units outstanding at March 31, 2024 and December 31, 2023, respectively	875,324		918,208
TOTAL EQUITY	875,324		918,208
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,231,675	$	1,266,884

The accompanying notes are an integral part of these unaudited consolidated financial statements.

1

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2024		2023
REVENUE
Oil and condensate sales	$	71,224	$	60,909
Natural gas and natural gas liquids sales	42,011		57,423
Lease bonus and other income	3,548		3,975
Revenue from contracts with customers	116,783		122,307
Gain (loss) on commodity derivative instruments	(11,290)		52,271
TOTAL REVENUE	105,493		174,578
OPERATING (INCOME) EXPENSE
Lease operating expense	2,432		2,668
Production costs and ad valorem taxes	13,038		12,667
Exploration expense	3		4
Depreciation, depletion, and amortization	11,639		11,147
General and administrative	14,090		12,648
Accretion of asset retirement obligations	317		245
TOTAL OPERATING EXPENSE	41,519		39,379
INCOME (LOSS) FROM OPERATIONS	63,974		135,199
OTHER INCOME (EXPENSE)
Interest and investment income	670		157
Interest expense	(629)		(814)
Other income (expense)	(88)		(99)
TOTAL OTHER EXPENSE	(47)		(756)
NET INCOME (LOSS)	63,927		134,443
Distributions on Series B cumulative convertible preferred units	(7,367)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	56,560	$	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	56,560		129,193
	$	56,560	$	129,193
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.27	$	0.62
Per common unit (diluted)	$	0.27	$	0.60
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	210,654		209,941
Weighted average common units outstanding (diluted)	210,654		224,910

 The accompanying notes are an integral part of these unaudited consolidated financial statements.

2

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)

	Common units	Partners' equity
BALANCE AT DECEMBER 31, 2023	209,991	$	918,208
Repurchases of common units	(287)	(4,381)
Restricted units granted, net of forfeitures	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
BALANCE AT MARCH 31, 2024	210,656	$	875,324

 

	Common units	Partners' equity
BALANCE AT DECEMBER 31, 2022	209,407	$	911,451
Repurchases of common units	(358)	(5,496)
Restricted units granted, net of forfeitures	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
BALANCE AT MARCH 31, 2023	209,963	$	939,867

The accompanying notes are an integral part of these unaudited consolidated financial statements.

3

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	63,927	$	134,443
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	11,639		11,147
Accretion of asset retirement obligations	317		245
Amortization of deferred charges	268		255
(Gain) loss on commodity derivative instruments	11,290		(52,271)
Net cash (paid) received on settlement of commodity derivative instruments	13,797		13,285
Equity-based compensation	2,383		2,118
Changes in operating assets and liabilities:
Accounts receivable	9,851		41,588
Prepaid expenses and other current assets	(220)		(182)
Accounts payable, accrued liabilities, and other	(8,510)		(13,333)
Settlement of asset retirement obligations	(282)		(140)
NET CASH PROVIDED BY OPERATING ACTIVITIES	104,460		137,155
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(22,966)		—
Additions to oil and natural gas properties	(285)		(1,932)
Additions to oil and natural gas properties leasehold costs	(753)		—
Purchases of other property and equipment	(39)		(22)
Proceeds from the sale of oil and natural gas properties	79		—
NET CASH USED IN INVESTING ACTIVITIES	(23,964)		(1,954)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to common unitholders	(99,899)		(99,600)
Distributions to Series B cumulative convertible preferred unitholders	(6,026)		(5,250)
Repurchases of common units	(4,381)		(5,496)
Borrowings under credit facility	6,000		50,000
Repayments under credit facility	(6,000)		(60,000)
Debt issuance costs and other	(16)		(12)
NET CASH USED IN FINANCING ACTIVITIES	(110,322)		(120,358)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(29,826)		14,843
CASH AND CASH EQUIVALENTS – beginning of the period	70,282		4,307
CASH AND CASH EQUIVALENTS – end of the period	$	40,456	$	19,150
SUPPLEMENTAL DISCLOSURE
Interest paid	$	361	$	588

 The accompanying notes are an integral part of these unaudited consolidated financial statements.

4

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - 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 three months ended March 31, 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.

5

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - 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 three months ended March 31, 2024.

Accounts Receivable

The following table presents information about the Partnership's accounts receivable:

	March 31, 2024		December 31, 2023
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	68,312	$	77,560
Other	4,116		4,693
Total accounts receivable	$	72,428	$	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.

NOTE 3 - OIL AND NATURAL GAS PROPERTIES    

Divestitures

The Partnership had no material divestiture activity during 2023 or the three months ended March 31, 2024.

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 first quarter of 2024, the Partnership acquired mineral and royalty interests that consisted of substantially all unproved oil and natural gas properties from various sellers for cash consideration of $23.0 million, including capitalized direct transaction costs. These acquisitions were considered asset acquisitions, were primarily located in the Gulf Coast land region, and were funded with cash from operating activities.

During the year ended December 31, 2023, the Partnership acquired mineral and royalty interests that consisted of unproved oil and natural gas properties from various sellers for cash consideration of $14.6 million, including capitalized direct transaction costs. These acquisitions were considered asset acquisitions, were primarily located in the Gulf Coast land region, and were funded with cash from operating activities.

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

6

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 portions of the Partnership's undeveloped acreage in San Augustine County, Texas. 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 March 31, 2024, 20 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	%

7

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Angelina Farmout

In May 2020, BSM and Aethon entered into an agreement to develop certain portions of the Partnership's undeveloped acreage 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 March 31, 2024, 45 wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

Aethon Time-Out

In December 2023, the Partnership received notice that Aethon was exercising the "time-out" provisions under its joint exploration agreements with BSM in Angelina and San Augustine counties in East Texas. When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. The current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months. Aethon has not previously invoked the time-out provisions under the agreements.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

The Partnership did not recognize any impairment of oil and natural gas properties for the three months ended March 31, 2024 and 2023. See "Note 5 - Fair Value Measurements" for additional information.

NOTE 4 - 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.

8

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 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 March 31, 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 March 31, 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:

		March 31, 2024
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	36,665	$	(5,924)	$	30,741
Long-term asset	Deferred charges and other long-term assets	512		(365)		147
Total assets		$	37,177	$	(6,289)	$	30,888
Liabilities:
Current liability	Commodity derivative liabilities	$	18,706	$	(5,924)	$	12,782
Long-term liability	Commodity derivative liabilities	6,223		(365)		5,858
Total liabilities		$	24,929	$	(6,289)	$	18,640

		December 31, 2023
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	41,485	$	(3,212)	$	38,273
Long-term asset	Deferred charges and other long-term assets	498		(126)		372
Total assets		$	41,983	$	(3,338)	$	38,645
Liabilities:
Current liability	Commodity derivative liabilities	$	4,441	$	(3,212)	$	1,229
Long-term liability	Commodity derivative liabilities	207		(126)		81
Total liabilities		$	4,648	$	(3,338)	$	1,310

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31,
Derivatives not designated as hedging instruments	2024		2023
	(in thousands)
Beginning fair value of commodity derivative instruments	$	37,335	$	28,941
Gain (loss) on oil derivative instruments	(23,230)		7,422
Gain (loss) on natural gas derivative instruments	11,940		44,849
Net cash paid (received) on settlements of oil derivative instruments	(121)		1,400
Net cash paid (received) on settlements of natural gas derivative instruments	(13,676)		(14,685)
Net change in fair value of commodity derivative instruments	(25,087)		38,986
Ending fair value of commodity derivative instruments	$	12,248	$	67,927

The Partnership had the following open derivative contracts for oil as of March 31, 2024:

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2024
First Quarter	190,000	$	71.45	$	67.00	$	81.00
Second Quarter	570,000	71.45		67.00		81.00
Third Quarter	570,000	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

The Partnership had the following open derivative contracts for natural gas as of March 31, 2024:

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2024
Second Quarter	10,465,000	$	3.55	$	3.00	$	3.76
Third Quarter	10,580,000	3.55		3.00		3.76
Fourth Quarter	10,580,000	3.55		3.00		3.76
2025
First Quarter	7,200,000	$	3.39	$	3.34	$	3.65
Second Quarter	7,280,000	3.39		3.34		3.65
Third Quarter	11,040,000	3.45		3.34		3.65
Fourth Quarter	11,040,000	3.45		3.34		3.65

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 - 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 three months ended March 31, 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 March 31, 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.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2024
Financial Assets
Commodity derivative instruments	$	—	$	37,177	$	—	$	(6,289)	$	30,888
Financial Liabilities
Commodity derivative instruments	$	—	$	24,929	$	—	$	(6,289)	$	18,640
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 three months ended March 31, 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 March 31, 2024 or December 31, 2023. There were no assets measured at fair value on a non-recurring basis for the three months ended March 31, 2024 or the year ended December 31, 2023.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 - 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. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2024.

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, (2) 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 March 31, 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 7.92% during the three months ended March 31, 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 March 31, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.

There was no aggregate principal balance outstanding at March 31, 2024 and December 31, 2023, respectively. The unused portion of the available borrowings under the Credit Facility was $375.0 million at March 31, 2024 and December 31, 2023.

NOTE 7 - 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.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2024 will be resolved without material adverse effect on the Partnership’s financial condition or operations. 

NOTE 8 - 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 March 31,
	2024		2023
	(in thousands)
Cash—short and long-term incentive plans	$	1,260	$	1,079
Equity-based compensation—restricted common units	996		954
Equity-based compensation—restricted performance units	738		633
Board of Directors incentive plan	649		531
Total incentive compensation expense	$	3,643	$	3,197

For the three months ended March 31, 2024, the Partnership repurchased 286,761 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.

In the first quarter of 2022, the board of directors of the Partnership's general partner (the "Board") approved a grant of awards to all employees dependent on the achievement of an aspirational production target to be measured in the fourth quarter of 2025 (the "Aspirational Awards"). The Aspirational Awards include performance cash awards and performance equity awards in the form of restricted performance units. To the extent earned, each performance unit represents the right to receive one common unit. The performance cash awards and performance units are eligible to become earned at the end of the requisite service period on December 31, 2025 if the minimum performance metrics are achieved. The minimum performance metrics are at least 42 Mboe per day of average daily royalty production in either the fourth quarter or the month of December of 2025 while maintaining a net debt to EBITDA ratio less than or equal to 1.0 on December 31, 2025. Average daily royalty production does not include production attributable to acquisitions consummated during the performance period. Compensation expense related to the Aspirational Awards will be recorded over the service period when achievement of the performance condition is probable. Total compensation expense to be recognized over the life of the Aspirational Awards consists of $5.6 million for the performance cash awards and $14.7 million for the performance equity awards (1,220,201 performance units with a weighted-average grant date fair value of $12.03 per unit). As of March 31, 2024, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

NOTE 9 - 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

14

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 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.

NOTE 10 - 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.

15

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the computation of basic and diluted earnings per common unit:

	Three Months Ended March 31,
	2024		2023
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	63,927	$	134,443
Distributions on Series B cumulative convertible preferred units	(7,367)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	56,560	$	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	56,560		129,193
	$	56,560	$	129,193
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders	$	56,560	$	129,193
Effect of dilutive securities	—		5,250
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$	56,560	$	134,443
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)	210,654		209,941
Effect of dilutive securities	—		14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	210,654		224,910
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.27	$	0.62
Per common unit (diluted)	$	0.27	$	0.60

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 March 31,
	2024	2023
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	15,072	—

NOTE 11 - 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. 

16

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 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 March 31,
	2024		2023
Distributions declared and paid per common unit	$	0.4750	$	0.4750

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 three months ended March 31, 2024. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.

NOTE 12 - SUBSEQUENT EVENTS    

Distribution

On April 17, 2024, the Board approved a distribution for the three months ended March 31, 2024 of $0.375 per common unit. Distributions will be payable on May 17, 2024 to unitholders of record at the close of business on May 10, 2024.

Acquisitions

Subsequent to March 31, 2024, the Partnership acquired mineral and royalty interests from various sellers for cash consideration of $12.3 million. These acquisitions were funded with cash from operating activities.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2023 ("2023 Annual Report on Form 10-K"). This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”

Cautionary Note Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•our ability to execute our business strategies;

•the volatility of realized oil and natural gas prices;

•the level of production on our properties;

•the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;

•our ability to replace our oil and natural gas reserves;

•general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;

•competition in the oil and natural gas industry;

•the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;

•the ability of our operators to obtain capital or financing needed for development and exploration operations;

•title defects in the properties in which we invest;

•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

•restrictions on the use of water for hydraulic fracturing;

•the availability of pipeline capacity and transportation facilities;

•the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

•future operating results;

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•future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;

•exploration and development drilling prospects, inventories, projects, and programs;

•operating hazards faced by our operators;

•the ability of our operators to keep pace with technological advancements;

•conservation measures and general concern about the environmental impact of the production and use of fossil fuels;

•cybersecurity incidents, including data security breaches or computer viruses; and

•certain factors discussed elsewhere in this filing.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our 2023 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.

Overview

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

As of March 31, 2024, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 68,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Recent Developments

Shelby Trough Development Update

A significant portion of Shelby Trough development in recent years has been performed by Aethon Energy (“Aethon”) under the two Joint Exploration Agreements (“JEAs”) between us and Aethon. The JEAs outline Aethon’s development obligations and other rights and obligations of each party related to our core mineral positions in San Augustine and Angelina counties in East Texas.

In December 2023, we received notice that Aethon was exercising the “time-out” provisions under these JEAs. When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. Aethon has not previously invoked the time-out provisions under the JEAs. We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations, and we are analyzing the potential impacts to us on an ongoing basis.

In April 2024, Aethon began curtailing production volumes on a small number of producing wells. This temporary decrease is expected to amount to approximately 800 Boe/d. Additionally, Aethon has indicated that it intends to curtail these

19

wells and delay the initial production of an additional 10 wells until the second half of the year, when natural gas prices are forecast to improve.

Austin Chalk Update

We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions. The results of the test program in the Brookeland Field demonstrated that modern completion technology has the potential to improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. To date, 30 wells with modern completions are being produced in the field.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.

Oil prices increased from the prior period ended March 31, 2023 as a result of heightened geopolitical risk related to the attacks targeting commercial ships transiting the Red Sea shipping channel and general elevated tensions around the region. In addition, the recent extension of OPEC+ voluntary production cuts add to upward price pressure at a time of the year when oil demand typically increases because of the spring and summer driving seasons in the Northern Hemisphere. Natural gas prices decreased from the prior period ended March 31, 2023 as a result of a large surplus of storage inventory. The United States started the winter heating season with a surplus and a mild winter led to below average consumption further increasing the surplus of storage inventory. Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

The following table reflects commodity prices at the end of each quarter presented:

	2024		2023
Benchmark Prices1	First Quarter		First Quarter
WTI spot oil price ($/Bbl)	$	83.96	$	75.68
Henry Hub spot natural gas ($/MMBtu)	1.54		2.10

1 Source: EIA

Rig Count

As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count at the end of each quarter presented:

	2024	2023
U.S. Rotary Rig Count1	First Quarter	First Quarter
Oil	506	592
Natural gas	112	160
Other	3	3
Total	621	755

1 Source: Baker Hughes Incorporated

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Natural Gas Storage

A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA expects inventories will rise to 4.1 Tcf at the end of October 2024, which would be 10% higher than the five-year average.

The following table shows natural gas storage volumes by region at the end of each quarter presented:

	2024	2023
Region1	First Quarter	First Quarter
East	363	335
Midwest	510	421
Mountain	162	80
Pacific	227	73
South Central	996	921
Total	2,258	1,830

1 Source: EIA

Natural Gas Exports

The EIA expects exports of natural gas, both by pipeline and as LNG, will increase in 2024. The EIA forecasts average exports of 12.2 Bcf per day for 2024, a 2% increase from 2023 levels.

In 2025, the EIA expects LNG exports to increase because three of the five LNG export projects currently under construction are expected to start operations and ramp up to full production. The EIA also expects natural gas exports by pipeline to grow because of increased natural gas exports to Mexico.

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How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

•volumes of oil and natural gas produced;

•commodity prices including the effect of derivative instruments; and

•Adjusted EBITDA and Distributable cash flow.

Volumes of Oil and Natural Gas Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States.

•Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("WTI"), is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products.  As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

•Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. 

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

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Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 2024 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed, but not required, to hedge, using collars and swaps with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2024, we had hedged 72% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively. As of March 31, 2024, we had also hedged 69% and 60% of our available natural gas hedge volumes for 2024 and 2025, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production. We do not enter into derivative instruments for speculative purposes.

Non-GAAP Financial Measures

Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.

Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies.

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The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:

	Three Months Ended March 31,
	2024		2023
	(in thousands)
Net income (loss)	$	63,927	$	134,443
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	11,639		11,147
Interest expense	629		814
Income tax expense (benefit)	135		147
Accretion of asset retirement obligations	317		245
Equity–based compensation	2,383		2,118
Unrealized (gain) loss on commodity derivative instruments	25,087		(38,986)
Adjusted EBITDA	104,117		109,928
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue	(1)		(5)
Cash interest expense	(361)		(559)
Preferred unit distributions	(7,367)		(5,250)
Distributable cash flow	$	96,388	$	104,114

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Results of Operations

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

The following table shows our production, revenue, and operating expenses for the periods presented:

	Three Months Ended March 31,
	2024		2023		Variance
	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	923		793		130		16.4	%
Natural gas (MMcf)1	16,470		16,452		18		0.1	%
Equivalents (MBoe)	3,668		3,535		133		3.8	%
Equivalents/day (MBoe)	40.3		39.3		1.0		2.5	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	77.17	$	76.81	$	0.36	0.5	%
Natural gas ($/Mcf)1	2.55		3.49		(0.94)		(26.9)	%
Equivalents ($/Boe)	$	30.87	$	33.47	$	(2.60)	(7.8)	%
Revenue:
Oil and condensate sales	$	71,224	$	60,909	$	10,315	16.9	%
Natural gas and natural gas liquids sales1	42,011		57,423		(15,412)		(26.8)	%
Lease bonus and other income	3,548		3,975		(427)		(10.7)	%
Revenue from contracts with customers	116,783		122,307		(5,524)		(4.5)	%
Gain (loss) on commodity derivative instruments	(11,290)		52,271		(63,561)		(121.6)	%
Total revenue	$	105,493	$	174,578	$	(69,085)	(39.6)	%
Operating expenses:
Lease operating expense	$	2,432	$	2,668	$	(236)	(8.8)	%
Production costs and ad valorem taxes	13,038		12,667		371		2.9	%
Exploration expense	3		4		(1)		(25.0)	%
Depreciation, depletion, and amortization	11,639		11,147		492		4.4	%
General and administrative	14,090		12,648		1,442		11.4	%
Other expense:
Interest expense	629		814		(185)		(22.7)	%

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Revenue

Total revenue for the quarter ended March 31, 2024 decreased compared to the quarter ended March 31, 2023. The decrease in total revenue in the first quarter of 2024 is primarily due to a loss on our commodity derivative instruments compared to a gain in the corresponding prior period and a decrease in natural gas and NGL sales which was partially offset by an increase in oil and condensate sales.

Oil and condensate sales. Oil and condensate sales increased for the quarter ended March 31, 2024 as compared to the corresponding period in 2023 primarily due to higher production volumes. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2024 and 2023, respectively.

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Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended March 31, 2024 as compared to the corresponding prior period. The decrease was due to lower realized commodity prices between the comparative periods. Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the quarters ended March 31, 2024 and 2023, respectively.

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the first quarter of 2024, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2023. For the three months ended March 31, 2024, we recognized $13.8 million of realized gains and $25.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.3 million of realized gains and $39.0 million of unrealized gains in the same period in 2023. The unrealized losses on our commodity contracts during the first quarter of 2024 were primarily driven by changes in the forward commodity price curves for oil and the unrealized gains in the same period in 2023 were driven by changes in the forward commodity price curves for natural gas.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2024 was lower than the same period in 2023. Leasing activity in the Austin Chalk play and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas made up the majority of lease bonus and other income for the first quarter of 2024, while the majority of the first quarter 2023 activity came from leasing activity in the Haynesville/Bossier play and the Permian Basin.

Operating Expenses

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended March 31, 2024, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2023, primarily due to severance tax refunds received in the first quarter of 2023 with no similar activity recorded in the first quarter of 2024.

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for the quarter ended March 31, 2024 and the corresponding prior period of 2023 was minimal.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended March 31, 2024 as compared to the same period in 2023 due to higher production volumes.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and the timing of annual tax services performed.

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Interest expense. Interest expense was lower in the first quarter of 2024 relative to the corresponding period in 2023, due to lower average outstanding borrowings under our Credit Facility. Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs.

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Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business. On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units 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. We have 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. See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

The Board has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions on our common units quarterly or on any other basis, and there is no guarantee that we will pay distributions to our common unitholders in any quarter. The Board may change the foregoing distribution policy at any time and from time to time.

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Cash Flows

The following table shows our cash flows for the periods presented: 

	Three Months Ended March 31,
	2024		2023		Change
	(in thousands)
Cash flows provided by operating activities	$	104,460	$	137,155	$	(32,695)
Cash flows provided by (used in) investing activities	(23,964)		(1,954)		(22,010)
Cash flows provided by (used in) financing activities	(110,322)		(120,358)		10,036

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreased for the three months ended March 31, 2024 as compared to the same period of 2023. The decrease was primarily due to reduced natural gas and NGL sales due to lower realized commodity prices in the three months ended March 31, 2024 compared to the same period of 2023.

Investing Activities. Net cash used in investing activities in the three months ended March 31, 2024 increased as compared to the same period of 2023. The increase was primarily due to acquisitions of oil and natural gas properties in the three months ended March 31, 2024 as compared to no acquisition activity in the corresponding prior period.

Financing Activities. Cash flows used in financing activities decreased for the three months ended March 31, 2024 as compared to the same period of 2023. The decrease was primarily due to net repayments on our Credit Facility for the three months ended March 31, 2023 compared to no net repayments for the three months ended March 31, 2024.

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Development Capital Expenditures

Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.3 million has been invested in the three months ended March 31, 2024. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest. Through March 31, 2024, we have also spent $0.7 million acquiring leases in areas around our drilling programs.

Acquisitions

During the three months ended March 31, 2024, we acquired mineral and royalty interests that consisted of substantially all unproved oil and natural gas properties from various sellers for cash consideration of $23.0 million, including capitalized direct transaction costs. These acquisitions were primarily located in the Gulf Coast land region and were funded with cash from operating activities. Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

See "Note 3 – Oil and Natural Gas Properties" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Credit Facility

We maintain 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 April and October. 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. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2024.

We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of March 31, 2024, we were in compliance with all debt covenants.

See "Note 6 – Credit Facility" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Contractual Obligations

As of March 31, 2024, there have been no material changes to our contractual obligations previously disclosed in our 2023 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of March 31, 2024, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2023 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures about Market Risk 

Commodity Price Risk

Our major market risk exposure is the pricing of oil, natural gas, and NGLs produced by our operators. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and NGLs have been historically volatile, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative financial instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash based on the difference between the fixed contract price and the market settlement price. The market settlement price is based on the NYMEX benchmark for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the

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change. See "Note 4 - Commodity Derivative Financial Instruments" and "Note 5 - Fair Value Measurements" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Commodity prices have been historically volatile based upon the dynamics of supply and demand. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the three months ended March 31, 2024. Applying this discount results in an approximate 2.2% reduction of proved reserve volumes as compared to the undiscounted March 31, 2024 SEC pricing scenario.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2024, we had seven counterparties, all of which were rated Baa2 or better by Moody’s and are lenders under our Credit Facility.

Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. During the three months ended March 31, 2024, we had $0.3 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted average interest rate of 7.92%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in a de minimis increase in interest expense, and a corresponding decrease in our results of operations, for the three months ended March 31, 2024, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place. 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2024 to provide reasonable assurance.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our 2023 Annual Report on Form 10-K. Except to the extent updated below, there has been no material change in our risk factors from those described in our 2023 Annual Report on Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth our purchases of our common units for each month during the three months ended March 31, 2024:

Purchases of Common Units
Period	Total Number of Common Units Purchased1	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs2
January 1 - January 31, 2024	92,614	$	16.04	—	$	150,000,000
February 1 - February 29, 2024	193,914	14.91		—	150,000,000
March 1 - March 31, 2024	233	15.05		—	150,000,000

1 Consists of units withheld to satisfy tax withholding obligations upon the vesting of certain long-term incentive equity awards held by our executive officers and certain other employees.

2 On October 30, 2023, the Board authorized the repurchase of up to $150.0 million in common units. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, 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 we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion.

Item 5. Other Information

During the three months ended March 31, 2024, none of our directors or executive officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.

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Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
3.2	Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
3.3	First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
3.4	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).
3.5	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).
3.6	Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).
3.7	Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of the Black Stone Minerals, L.P., dated as of April 22, 2020 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on April 24, 2020 (SEC File No. 001-37362)).
4.1	Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).
10.1^*	2024 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Restricted Units) under the Black Stone Minerals, L.P. Long-Term Incentive Plan.
10.2^*	2024 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Performance Units) under the Black Stone Minerals, L.P. Long-Term Incentive Plan.
31.1*	Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	Inline XBRL Schema Document
101.CAL*	Inline XBRL Calculation Linkbase Document
101.LAB*	Inline XBRL Label Linkbase Document
101.PRE*	Inline XBRL Presentation Linkbase Document
101.DEF*	Inline XBRL Definition Linkbase Document
104*	Cover Page Interactive Data File - the cover page iXBRL tags are embedded within the Inline XBRL document.

*    Filed or furnished herewith.

^ Management contract or compensatory plan or arrangement

32

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

	BLACK STONE MINERALS, L.P.
	By:	Black Stone Minerals GP, L.L.C., its general partner
Date: May 7, 2024	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		President, Chief Executive Officer, and Chairman
		(Principal Executive Officer)
Date: May 7, 2024	By:	/s/ Evan M. Kiefer
		Evan M. Kiefer
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

33

EX-10.1

Exhibit 10.1

BLACK STONE MINERALS, L.P.

LONG-TERM INCENTIVE PLAN

RESTRICTED UNIT AWARD GRANT NOTICE

Pursuant to the terms and conditions of the Black Stone Minerals, L.P. Long-Term Incentive Plan, as amended from time to time (the “Plan”), Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), hereby grants to the individual listed below (“you” or “Employee”) the number of Restricted Units (all of which shall consist of Common Units) set forth below (the “Restricted Units”). This award of Restricted Units (this “Award”) is subject to the terms and conditions set forth herein as well as the terms and conditions set forth in the Restricted Unit Award Agreement attached hereto as Exhibit A (the “Agreement”) and in the Plan, each of which is incorporated herein by reference. Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.

Employee:	[FIRSTNAME] [MIDDLENAME] [LASTNAME]
Date of Grant:	[GRANTDATE]
Employer:	Black Stone Natural Resources Management Company or any other entity that may employ Employee after the Date of Grant and which entity is the General Partner, Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), or any of their respective Affiliates.
Number of Restricted Units Granted: Qualifying Termination Percentage:	[SHARESGRANTED] Restricted Units [●]%
Vesting Schedule:	Subject to the Agreement, the Plan and the other terms and conditions set forth herein, the Restricted Units (rounded to the nearest whole number of Restricted Units, except in the case of the final vesting date) shall vest in accordance with the following schedule so long as you remain continuously employed by the Employer from the Date of Grant through each vesting date set forth below:
	Vesting Date [●] [●] [●]	Portion of the Award that Becomes Vested 1/3 1/3 1/3

By clicking to accept, you agree to be bound by the terms and conditions of the Plan, the Agreement and this Restricted Unit Award Grant Notice (this “Grant Notice”). You acknowledge that you have reviewed the Agreement, the Plan and this Grant Notice in their entirety and fully understand all provisions of the Agreement, the Plan and this Grant Notice. You hereby agree to accept as binding, conclusive and final all decisions or interpretations of the Committee regarding any questions or determinations arising under the Agreement, the Plan or this Grant Notice.

In lieu of receiving documents in paper format, you agree, to the fullest extent permitted by applicable law, to accept electronic delivery of any documents that the General Partner or any Affiliate may be required to deliver (including prospectuses, prospectus supplements, grant or award notifications and agreements, account statements, annual and quarterly reports, and all other forms of communications) in connection with this and any other award made or offered by the General Partner. Electronic delivery may be made via the electronic mail system of the General Partner or one of its Affiliates or by reference to a location on an intranet site to which you have access. You hereby consent to any and all procedures the General Partner has established or may establish for an electronic signature system for delivery and acceptance of any such documents.

You also understand and acknowledge that you should consult with your tax advisor regarding the advisability of filing with the Internal Revenue Service an election under Section 83(b) of the Internal Revenue Code (a “Section 83(b) Election”) with respect to the Restricted Units. This election must be filed no later than 30 days after Date of Grant. This time period cannot be extended. If you wish to file a Section 83(b) Election, an election form is attached to this Grant Notice as Exhibit B. By clicking to accept, you acknowledge that (a) you have been advised to consult with a tax advisor regarding the tax consequences of the Restricted Units and (b) the timely filing of a Section 83(b) Election is your sole responsibility, even if you request the Employer, the General Partner or any of their respective Affiliates or any of their respective managers, directors, officers, employees or authorized representatives (including attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial representatives) to assist in making such filing or to file such election on your behalf.

You acknowledge and agree that clicking to accept this Award constitutes your electronic signature and is intended to have the same force and effect as your manual signature.

Remainder of Page Intentionally Blank;

Signature Page Follows

2

IN WITNESS WHEREOF, the General Partner has caused this Grant Notice to be executed by an officer thereunto duly authorized effective for all purposes as provided above.

BLACK STONE MINERALS GP, L.L.C.

By:

Steve Putman

Senior Vice President, General Counsel, and Secretary

Signature Page to

Restricted Unit Award Grant Notice

EXHIBIT A

RESTRICTED UNIT AWARD AGREEMENT

This Restricted Unit Award Agreement (this “Agreement”) is made as of the Date of Grant set forth in the Grant Notice to which this Agreement is attached (the “Date of Grant”) by and between Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), and [ ] (“Employee”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Plan or the Grant Notice.

1.Award.  Effective as of the Date of Grant, the General Partner hereby grants to Employee the number of Restricted Units (all of which shall consist of Common Units) set forth in the Grant Notice (the “Restricted Units”) on the terms and conditions set forth in the Grant Notice, this Agreement and the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan shall control.

2.Issuance Mechanics. The General Partner shall (a) cause a certificate or certificates representing such Common Units to be registered in the name of Employee, or (b) cause such Common Units to be held in book-entry form.  If a certificate is issued, it shall be delivered to and held in custody by the General Partner and shall bear such legend or legends as the Committee deems appropriate in order to reflect the Forfeiture Restrictions (as defined below) and to ensure compliance with the terms and provisions of this Agreement, the rules, regulations and other requirements of the United States Securities and Exchange Commission, any applicable federal or state securities laws or any securities exchange on which the Common Units are then listed or quoted. If the Common Units are held in book-entry form, then such entry will reflect that the Common Units are subject to the restrictions of this Agreement.

3.Forfeiture Restrictions. 

(a)The Restricted Units may not be sold, assigned, pledged, exchanged, hypothecated or otherwise transferred, encumbered or disposed of except as provided in this Agreement or the Plan. In the event of the termination of Employee’s employment with the Employer, except as otherwise expressly provided in this Agreement, Employee shall immediately and without any further action by the General Partner, forfeit and surrender for no consideration all of the Restricted Units with respect to which the Forfeiture Restrictions have not lapsed as of the date of such termination. The prohibition against transfer and the obligation to forfeit and surrender the Restricted Units upon termination of Employee’s employment as provided in this Section 3(a) are referred to herein as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding upon and enforceable against any transferee of the Restricted Units.

(b)In the event of a Qualifying Termination (as defined in Section 3(d)) prior to the vesting of all of the Restricted Units, subject to Employee’s compliance with the release requirement described in Section 3(f), the Forfeiture Restrictions on the Applicable Restricted

Exhibit A-1

Units (as defined in Section 3(d)) shall automatically lapse and the Applicable Restricted Units shall immediately thereafter become Earned Units so long as Employee has remained continuously employed by the Employer from the Date of Grant through the date of such Qualifying Termination; provided, however, that if such Qualifying Termination occurs within 24 months following a Change of Control, the Forfeiture Restrictions on all unvested Restricted Units will lapse automatically in accordance with Section 3(e) without any further action by the General Partner or the Partnership and such Restricted Units shall immediately thereafter become Earned Units so long as Employee has remained continuously employed by the Employer from the Date of Grant through the date of such Qualifying Termination.

(c)In the event of a termination of Employee’s employment due to Employee’s Disability (as defined in Section 3(d)) or death prior to the vesting of all of the Restricted Units, the Forfeiture Restrictions on all unvested Restricted Units will lapse automatically in accordance with Section 3(e) without any further action by the General Partner or the Partnership and such Restricted Units shall immediately thereafter become Earned Units so long as Employee has remained continuously employed by the Employer from the Date of Grant through the date of such termination.

(d)As used herein, the following terms have the meanings set forth below:

(i)“Applicable Restricted Units” means the number of Restricted Units equal to A minus B, where “A” is the product of (x) the number of Restricted Units granted hereunder,(y) a fraction, the numerator of which is the number of days during the period beginning on the Date of Grant and ending on the date of Employee’s Qualifying Termination, and the denominator of which is the number of days during the period beginning on the Date of Grant and ending on the last vesting date set forth in the Grant Notice, and, (z) the Qualifying Termination Percentage set forth in the Grant Notice; and “B” is the cumulative number of Restricted Units that became vested prior to the date of Employee’s Qualifying Termination.

(ii)“Cause” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Cause,” then “Cause” means a determination by two-thirds of the Board that Employee:

(1)willfully and continually failed to substantially perform Employee’s duties to the Partnership and its Affiliates (other than a failure resulting from Employee’s Disability);

(2)willfully engaged in conduct that is demonstrably and materially injurious to the Partnership, the General Partner or any of their respective Affiliates, monetarily or otherwise;

(3)has been convicted of, or has plead guilty or nolo contendere to, a misdemeanor involving moral turpitude or a felony;

Exhibit A-2

(4)has committed an act of fraud, or material embezzlement or material theft, in each case, in the course of Employee’s employment relationship with the Employer or one of its Affiliates, or

(5)has materially breached any obligations of Employee under any written agreement (including any non-compete, non-solicitation or confidentiality covenants) entered into between Employee and the Partnership, the General Partner or any of their respective Affiliates.

Notwithstanding the foregoing, except for a failure, breach or refusal that, by its nature, cannot reasonably be expected to be cured, Employee shall have 30 days following the delivery of written notice by the Employer or one of its Affiliates within which to cure any actions or omissions described in clauses (1), (2), (4) or (5) constituting Cause; providedhowever, that, if the Employer reasonably expects irreparable injury from a delay of 30 days, the Employer or one of its Affiliates may give Employee notice of such shorter period within which to cure as is reasonable under the circumstances, which may include the termination of Employee’s employment without notice and with immediate effect.

(iii)“Disability” means Employee’s incapacity, due to accident, sickness or another circumstance, that renders Employee unable to perform the essential functions of Employee’s job function, with reasonable accommodation, for a period of at least 90 consecutive days or 120 days in any 12-month period.

(iv)“Good Reason” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Good Reason,” then “Good Reason” means the occurrence of any of the following events without Employee’s written consent:

(1)a reduction in Employee’s total compensation other than a general reduction in compensation that affects all similarly situated employees in substantially the same proportions;

(2)a relocation of Employee’s principal place of employment by more than 50 miles from the location of Employee’s principal place of employment as of the Date of Grant;

(3)any material breach by the Partnership or the General Partner of any material provision of this Agreement;

(4)a material, adverse change in Employee’s title, authority, duties or responsibilities (other than while Employee has a Disability);

Exhibit A-3

(5)a material adverse change in the reporting structure applicable to Employee; or

(6)following a Change of Control, either (x) a failure of the General Partner or one of its Affiliates to continue in effect any benefit plan or compensation arrangement in which Employee was participating immediately prior to such Change of Control or (y) the taking of any action by the General Partner or one of its Affiliates that adversely affects Employee’s participation in, or materially reduces Employee’s benefits or compensation under, any such benefit plan or compensation arrangement, unless, in the case of either clause (x) or (y), there is substituted a comparable benefit plan or compensation arrangement that is at least economically equivalent to the benefit plan or compensation arrangement being terminated or in which Employee’s participation is being adversely affected or Employee’s benefits or compensation are being materially reduced.

Notwithstanding the foregoing provisions of this definition or any other provision of the Agreement to the contrary, any assertion by Employee of a termination for Good Reason shall not be effective unless all of the following conditions are satisfied: (A) Employee must provide written notice to the General Partner of the existence of the condition(s) providing grounds for termination for Good Reason within 30 days of the initial existence of such grounds; (B) the condition(s) specified in such notice must remain uncorrected for 30 days following the General Partner’s receipt of such written notice; and (C) the date of Employee’s termination of employment must occur within 60 days after the initial existence of the condition(s) specified in such notice.

(v)“Qualifying Termination” means a termination of Employee’s employment by reason of (1) a termination of Employee’s employment by the Employer without Cause, or (2) Employee’s resignation for Good Reason.

(e)The Restricted Units shall be released from the Forfeiture Restrictions in accordance with the vesting schedule set forth in the Grant Notice.  The Restricted Units with respect to which the Forfeiture Restrictions lapse without forfeiture are referred to herein as the “Earned Units.” As soon as administratively practicable following the release of any Restricted Units from the Forfeiture Restrictions, the General Partner shall, as applicable, either deliver to Employee the certificate or certificates representing such Common Units in the General Partner’s possession belonging to Employee, or, if the Common Units are held in book-entry form, then the General Partner shall remove the notations indicating that the Common Units are subject to the restrictions of this Agreement.  Employee (or the beneficiary or personal representative of Employee in the event of Employee’s death or disability, as the case may be) shall deliver to the General Partner any representations or other documents or assurances as the General Partner or its representatives deem necessary or advisable in connection with any such delivery.

Exhibit A-4

(f)As a condition to any accelerated vesting described herein, Employee must first execute within the time provided to do so (and not revoke in any time provided to do so), a release, in a form acceptable to the General Partner, releasing the Committee, the Employer, the Partnership, the General Partner, their respective Affiliates, and each of the foregoing entities’ respective shareholders, members, partners, officers, managers, directors, fiduciaries, employees, representatives, agents and benefit plans (and fiduciaries of such plans) from any and all claims, including any and all causes of action arising out of Employee’s employment with the Employer and any of its Affiliates or the termination of such employment, but excluding all claims to payments under the Plan and this Agreement.

4.Distributions. Distributions that are paid or distributed with respect to a Restricted Unit (whether in the form of Units or other property (including cash)) shall be paid and distributed to Employee on or within 30 days following the date distributions are made to the unitholders of the Partnership, regardless of whether the Restricted Units have become vested. Distributions paid or distributed in the form of securities with respect to Restricted Units shall bear such legends, if any, as may be determined by the Committee from time to time to reflect the terms and conditions of this Agreement and to comply with applicable securities laws.

5.Rights as Unitholder.  Except as otherwise provided herein, upon issuance of the Restricted Units, Employee shall have all the rights of a holder of Common Units with respect to such Restricted Units subject to the restrictions herein, including the right to vote the Common Units.

6.Tax Withholding. Upon any taxable event arising in connection with the Restricted Units, the General Partner shall have the authority and the right to deduct or withhold (or cause the Employer or one of its Affiliates to deduct or withhold), or to require Employee to remit to the General Partner (or the Employer or one of its Affiliates), an amount sufficient to satisfy all applicable federal, state and local taxes required by law to be withheld with respect to such event. In satisfaction of the foregoing requirement, unless otherwise determined by the Committee, the General Partner or the Employer or one of its Affiliates shall withhold, or cause to be surrendered, from any cash or equity remuneration (including any of the Common Units issued under this Agreement) then or thereafter payable to Employee an amount equal to the aggregate amount of taxes required to be withheld with respect to such event. If such tax obligations are satisfied through the withholding or surrender of Common Units pursuant to this Agreement, the number of Common Units so withheld (or surrendered) shall be the number of Common Units that have an aggregate Fair Market Value on the date of withholding equal to the aggregate amount of taxes required to be withheld, determined based on the greatest withholding rates for federal, state, local and foreign income tax and payroll tax purposes, as determined by the Committee. Employee acknowledges and agrees that none of the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates has made any representation or warranty as to the tax consequences to Employee as a result of the receipt of the Restricted Units, the lapse of any Forfeiture Restrictions or the forfeiture of any of the Restricted Units pursuant to the Forfeiture Restrictions. Employee represents that he is in no manner relying on the Board, the Committee, the Partnership, General Partner, the Employer or any of

Exhibit A-5

their respective Affiliates or any of their respective managers, directors, officers, employees or authorized representatives (including, without limitation, attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial representatives) for tax advice or an assessment of such tax consequences. Employee represents that he has consulted with any tax consultants that Employee deems advisable in connection with the Restricted Units.

7.Refusal to Transfer; Stop-Transfer Notices.  The Partnership shall not be required (a) to transfer on its books any Common Units that have been sold or otherwise transferred in violation of any of the provisions of this Agreement or (b) to treat as owner of such Common Units or to accord the right to vote or pay distributions to any purchaser or other transferee to whom such Common Units shall have been so transferred.  Employee agrees that, in order to ensure compliance with the restrictions referred to herein, the Partnership or the General Partner may issue appropriate “stop transfer” instructions to its transfer agent, if any, and that, if the Partnership transfers its own securities, it may make appropriate notations to the same effect in its own records.

8.Restricted Units Not Transferable.  Prior to becoming Earned Units, the Restricted Units may not be (a) sold, pledged, assigned or transferred in any manner during the lifetime of Employee other than by will or the laws of descent and distribution, unless and until the Forfeiture Restrictions have lapsed, or (b) liable for the debts, contracts or engagements of Employee or his or her successors in interest. Except to the extent expressly permitted by the preceding sentence, any purported sale, pledge, assignment, transfer, attachment or encumbrance of the Restricted Units or any interest or right therein shall be null, void and unenforceable against the Partnership, the General Partner, the Employer and their respective Affiliates.

9.Section 83(b) Election. If Employee makes an election under Section 83(b) of the Code to be taxed with respect to the Restricted Units as of the Date of Grant rather than as of the date or dates upon which Employee would otherwise be taxable under Section 83(a) of the Code, Employee hereby agrees to (a) use the election form provided in Exhibit B for such purpose and (b) deliver a copy of such election to the General Partner promptly after filing such election with the Internal Revenue Service.

10.No Right to Continued Employment or Awards.

(a)For purposes of this Agreement, Employee shall be considered to be employed by the Employer as long as Employee remains an “Employee” (as such term is defined in the Plan), or an employee of a corporation or other entity (or a parent or subsidiary of such corporation or other entity) assuming or substituting a new award for this Award. Without limiting the scope of the preceding sentence, it is specifically provided that Employee shall be considered to have terminated employment at the time of the termination of the status of the entity or other organization that employs Employee as an “Affiliate” of the General Partner. Nothing in the adoption of the Plan, nor the grant of the Restricted Units pursuant to the Grant Notice and this Agreement, shall confer upon Employee the right to continued employment by, or a continued service relationship with, the Employer or any of its Affiliates, or any other entity,

Exhibit A-6

or affect in any way the right of the Employer or any such Affiliate, or any other entity to terminate such employment at any time. Unless otherwise provided in a written employment agreement or by applicable law, Employee’s employment by the Employer, or any such Affiliate, or any other entity shall be on an at-will basis, and the employment relationship may be terminated at any time by either Employee or the Employer, or any such Affiliate, or other entity for any reason whatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of such employment, and the cause of such termination, shall be determined by the Committee or its delegate, and such determination shall be final, conclusive and binding for all purposes.

(b)The grant of the Restricted Units is a one-time Award and does not create any contractual or other right to receive a grant of Awards or benefits in lieu of Awards in the future. Future Awards will be at the sole discretion of the Committee.

11.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of Employee, such notices or communications shall be effectively delivered if hand delivered to Employee at Employee’s principal place of employment or if sent by registered or certified mail to Employee at the last address Employee has filed with the Employer. In the case of the Partnership or General Partner, such notices or communications shall be effectively delivered if sent by registered or certified mail to the General Partner at its principal executive offices.

12.Agreement to Furnish Information. Employee agrees to furnish to the General Partner all information requested by the General Partner to enable the General Partner or any of its Affiliates to comply with any reporting or other requirement imposed upon the General Partner or any of its Affiliates by or under any applicable statute or regulation.

13.Entire Agreement; Amendment. This Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the Restricted Units granted hereunder; provided, however, that the terms of this Agreement shall not modify and shall be subject to the terms and conditions of any employment and/or severance agreement between the Partnership, the General Partner, the Employer or any of their respective Affiliates and Employee in effect as of the date a determination is to be made under this Agreement. Without limiting the scope of the preceding sentence, except as provided therein, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. The Committee may, in its sole discretion, amend this Agreement from time to time in any manner that is not inconsistent with the Plan; provided, however, that except as otherwise provided in the Plan or this Agreement, any such amendment that materially reduces the rights of Employee shall be effective only if it is in writing and signed by both Employee and an authorized officer of the General Partner.

Exhibit A-7

14.Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of law principles thereof.

15.Successors and Assigns. The General Partner may assign any of its rights under this Agreement without Employee’s consent. This Agreement will be binding upon and inure to the benefit of the successors and assigns of the General Partner. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement will be binding upon Employee and Employee's beneficiaries, executors, administrators and the person(s) to whom the Restricted Units may be transferred by will or the laws of descent or distribution.

16.Clawback. Notwithstanding any provision in this Agreement or the Grant Notice to the contrary, to the extent required by (a) applicable law, including, without limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards and/or (b) any policy that may be adopted or amended by the Board from time to time, all Restricted Units granted hereunder shall be subject to forfeiture, repurchase, recoupment and/or cancellation to the extent necessary to comply with such law(s) and/or policy.

17.Severability. If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of such provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.

Remainder of Page Intentionally Blank

Exhibit A-8

EXHIBIT B

SECTION 83(b) ELECTION

The undersigned taxpayer hereby elects, pursuant to Section 83(b) of the Internal Revenue Code of 1986, as amended, to include in gross income as compensation for services the excess (if any) of the fair market value of the property described below over the amount paid for such property.

1.    The name, taxpayer identification number and address of the undersigned (the “Taxpayer”), and the taxable year for which this election is being made are:

Taxpayer’s Name:        

Taxpayer’s Social

Security Number:        --

Taxpayer’s Address:          

Taxable Year:            Calendar Year

2.    The property that is the subject of this election (the “Property”) is ________ common units of Black Stone Minerals, L.P.

3.    The Property was transferred to the Taxpayer on ___________________.

4.    The Property is subject to the following restrictions: The units are subject to various transfer restrictions and are subject to forfeiture in the event certain service conditions are not satisfied.

5.    The fair market value of the Property at the time of transfer (determined without regard to any restriction other than a nonlapse restriction as defined in Section 1.83-3(h) of the Income Tax Regulations) is $__________ per unit x ________ units = $_______________.

6.    The amount paid by the Taxpayer for the Property is $__________ per unit x ________ units = $_______________.

7.    The amount to include in gross income is $_______________.

The undersigned taxpayer will file this election with the Internal Revenue Service office with which the taxpayer files his or her annual income tax return not later than 30 days after the date of transfer of the Property. A copy of the election also will be furnished to the person for whom the services were performed. Additionally, the undersigned will include a copy of the election with his or her income tax return for the taxable year in which the Property is transferred. The undersigned is the person performing the services in connection with which the Property was transferred.

Dated:

                            Taxpayer’s Signature

Exhibit B-1

EX-10.2

Exhibit 10.2

BLACK STONE MINERALS, L.P.

LONG-TERM INCENTIVE PLAN

LTI AWARD GRANT NOTICE

Pursuant to the terms and conditions of the Black Stone Minerals, L.P. Long-Term Incentive Plan, as amended from time to time (the “Plan”), Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), hereby grants to the individual listed below (“you” or “Employee”) the number of performance-based Phantom Units (the “Performance Units”) set forth below. This award of Performance Units (this “Award”) is subject to the terms and conditions set forth herein as well as the terms and conditions set forth in the LTI Award Agreement attached hereto as Exhibit A (the “Agreement”) and in the Plan, each of which is incorporated herein by reference. Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.

Employee:	[FIRSTNAME] [MIDDLENAME] [LASTNAME]
Date of Grant:	[GRANTDATE]
Employer:	Black Stone Natural Resources Management Company or any other entity that may employ Employee after the Date of Grant and which entity is the General Partner, Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), or any of their respective Affiliates.
Target Performance Units:	[SHARESGRANTED] Performance Units (the “Target Amount Performance Units”)
Performance Period: Qualifying Termination Percentage:	January 1, [●] through December 31, [●] [●]%
Earning of Performance Units:	Subject to the terms and conditions set forth herein, in the Agreement and in the Plan, the Performance Units shall become earned in the manner set forth below so long as you remain continuously employed by the Employer from the Date of Grant through the end of the Performance Period. The number of Performance Units, if any, that become earned in the Performance Period will be determined in accordance with the following table (the “Performance Goals”):
		Below Threshold	Threshold	Target	Maximum
	Average Performance Percentage	< 70%	70%	100%	130%

Percentage of Target Amount Performance Units that are Earned*	0%	50%	100%	200%
*If the Average Performance Percentage is between the Threshold amount and the Target amount set forth in the first row of the table above, then the percentage of the Target Amount Performance Units that are earned shall be determined by linear interpolation between Threshold (50%) and Target (100%) based on the Average Performance Percentage. If the Average Performance Percentage is between the Target amount and the Maximum amount set forth in the first row of the table above, then the percentage of the Target Amount Performance Units that are earned shall be determined by linear interpolation between Target (100%) and Maximum (200%) based on the Average Performance Percentage. Each percentage of Target Amount Performance Units that are earned as determined by linear interpolation shall be rounded to four decimal places. As used herein, the following terms have the meanings set forth below: “Average Performance Percentage” means, except as otherwise provided in the Agreement with respect to a Qualifying Termination, the average of the Production Performance Percentage and the Reserve Performance Percentage for the three Performance Period Years in the Performance Period. “BOE” means a barrel of oil equivalent that is one barrel (42 US gallons) of crude oil or six thousand (6,000) cubic feet of natural gas. “Budget” means, with respect to a Performance Period Year, the annual budget adopted by the Board for such Performance Period Year. “Performance Period Year” means each calendar year during the Performance Period. “Production Performance Percentage” means, with respect to a Performance Period Year, the quotient of (i) the amount of production (expressed as BOE) achieved by the Partnership and its subsidiaries for such Performance Period Year per weighted average Units outstanding for such Performance Period Year divided by (ii) the Production Target for such Performance Period Year per budgeted weighted average Units outstanding for such Performance Period Year. “Production Target” means, with respect to a Performance Period Year, the budgeted amount of the Partnership’s and its subsidiaries’ production (expressed as BOE) for such Performance Period Year set forth in the Budget for such Performance Period Year.

2

“Reserve Performance Percentage” means, with respect to a Performance Period Year, the quotient of (i) the amount of the Partnership’s and its subsidiaries’ reserves (expressed as BOE) as of the last day of such Performance Period Year per Units outstanding on the last day of such Performance Period Year divided by (ii) the Reserve Target for such Performance Period Year per budgeted Units outstanding on the last day of such Performance Period Year.

“Reserve Target” means, with respect to a Performance Period Year, the budgeted amount of the Partnership’s and its subsidiaries’ reserves (expressed as BOE) as of the last day of such Performance Period Year as set forth in the Budget for such Performance Period Year.

“Unit” has the meaning given to it in the Partnership Agreement and shall include the Preferred Units (as defined in the Partnership Agreement) on an as-converted basis.

By clicking to accept, you agree to be bound by the terms and conditions of the Plan, the Agreement and this LTI Award Grant Notice (this “Grant Notice”). You acknowledge that you have reviewed the Agreement, the Plan and this Grant Notice in their entirety and fully understand all provisions of the Agreement, the Plan and this Grant Notice. You hereby agree to accept as binding, conclusive and final all decisions or interpretations of the Committee regarding any questions or determinations arising under the Agreement, the Plan or this Grant Notice.

In lieu of receiving documents in paper format, you agree, to the fullest extent permitted by applicable law, to accept electronic delivery of any documents that the General Partner or any Affiliate may be required to deliver (including prospectuses, prospectus supplements, grant or award notifications and agreements, account statements, annual and quarterly reports, and all other forms of communications) in connection with this and any other award made or offered by the General Partner. Electronic delivery may be made via the electronic mail system of the General Partner or one of its Affiliates or by reference to a location on an intranet site to which you have access. You hereby consent to any and all procedures the General Partner has established or may establish for an electronic signature system for delivery and acceptance of any such documents.

You acknowledge and agree that clicking to accept this Award constitutes your electronic signature and is intended to have the same force and effect as your manual signature.

Remainder of Page Intentionally Blank;

Signature Page Follows

3

IN WITNESS WHEREOF, the General Partner has caused this Grant Notice to be executed by an officer thereunto duly authorized effective for all purposes as provided above.

BLACK STONE MINERALS GP, L.L.C.

By:

Steve Putman

Senior Vice President, General Counsel, and Secretary

Signature Page to

LTI Award Grant Notice

EXHIBIT A

LTI AWARD AGREEMENT

This LTI Award Agreement (this “Agreement”) is made as of the Date of Grant set forth in the Grant Notice to which this Agreement is attached (the “Date of Grant”) by and between Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), and [ ] (“Employee”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Plan or the Grant Notice.

1.Award.  Effective as of the Date of Grant, the General Partner hereby grants to Employee the number of performance-based Phantom Units set forth in the Grant Notice (the “Performance Units”) on the terms and conditions set forth in the Grant Notice, this Agreement and the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan shall control. To the extent earned, each Performance Unit represents the right to receive one Common Unit, subject to the terms and conditions set forth in the Grant Notice, this Agreement and the Plan. Unless and until the Performance Units have become earned in the manner set forth in the Grant Notice and this Agreement, Employee will have no right to receive any Common Units or other payments in respect of the Performance Units. Prior to settlement of this Award, the Performance Units and this Award represent an unsecured obligation of Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), payable only from the general assets of the Partnership.

2.Earning of Performance Units. 

(a)Following the end of the Performance Period, the Committee will determine the level of achievement of the Performance Goals for the Performance Period. The number of Performance Units, if any, that actually become earned for the Performance Period will be determined by the Committee in accordance with the Grant Notice (and any Performance Units that do not become so earned shall be automatically forfeited). Unless and until the Performance Units have become earned and been settled in accordance with Section 3, Employee will have no right to receive any distributions with respect to the Performance Units. In the event of the termination of Employee’s employment prior to the last day of the Performance Period, except as otherwise provided in Sections 2(b) and 2(c) below, all of the Performance Units (and all rights arising from such Performance Units and from being a holder thereof), will terminate automatically without any further action by the General Partner or the Partnership and will be automatically forfeited without further notice.

(b)In the event of a Qualifying Termination (as defined in Section 2(e)) prior to the end of the Performance Period and prior to a Change of Control or more than 24 months following a Change of Control, then, subject to Employee’s compliance with the release requirement described in Section 2(d), notwithstanding anything to the contrary in the Grant Notice, (i) the Performance Period shall end as of the date of such Qualifying Termination; (ii) the definition of “Average Performance Percentage” shall mean the average of (x) the

Exhibit A-1

Production Performance Percentage(s) and the Reserve Performance Percentage(s) for each completed Performance Period Year, if any, ending prior to the date of such Qualifying Termination and (y) the Production Performance Percentage and the Reserve Performance Percentage for the Performance Period Year in which such Qualifying Termination occurs (determined based on year-to-date annualized performance as of the date of such Qualifying Termination); and (iii) the number of Performance Units, if any, that actually become earned for the Performance Period as of the date of such Qualifying Termination shall be determined by multiplying (x) Employee’s Target Amount Performance Units for the Performance Period by (y) a fraction, the numerator of which is the number of days Employee was employed by the Employer during the Performance Period and the denominator of which is the number of days in the Performance Period, and by (z) the Qualifying Termination Percentage set forth in the Grant Notice.

(c)If a Qualifying Termination occurs within 24 months following a Change of Control or in the event of a termination of Employee’s employment due to Employee’s Disability or death prior to the end of the Performance Period, then, subject to Employee’s compliance with the release requirement described in Section 2(d), notwithstanding anything to the contrary in the Grant Notice, the number of Performance Units, if any, that actually become earned for the Performance Period will be determined by the Committee in accordance with the Grant Notice assuming that (i) the Performance Period ended as of the date of such termination of employment; and (ii) the definition of “Average Performance Percentage” means the average of (x) the Production Performance Percentage(s) and the Reserve Performance Percentage(s) for each completed Performance Period Year, if any, ending prior to the date of such termination of employment, (y) the Production Performance Percentage and the Reserve Performance Percentage for the Performance Period Year in which such termination of employment occurs (determined based on year-to-date annualized performance as of the date of such termination of employment), and (z) the Production Performance Percentage(s) and the Reserve Performance Percentage(s) for the remaining Performance Period Year(s), if any, assuming the Production Performance Percentage and the Reserve Performance Percentage are each 100% for each such Performance Period Year.

(d)As a condition to the application of the provisions of Section 2(b) or Section 2(c) (other than in the event of a termination of Employee’s employment due to Employee’s death), Employee must first execute within the time provided to do so (and not revoke in any time provided to do so), a release, in a form acceptable to the General Partner, releasing the Committee, the Employer, the Partnership, the General Partner, their respective Affiliates, and each of the foregoing entities’ respective shareholders, members, partners, officers, managers, directors, fiduciaries, employees, representatives, agents and benefit plans (and fiduciaries of such plans) from any and all claims, including any and all causes of action arising out of Employee’s employment with the Employer and any of its Affiliates or the termination of such employment, but excluding all claims to payments under the Plan and this Agreement.

(e)As used herein, the following terms have the meanings set forth below:

Exhibit A-2

(i)“Cause” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Cause,” then “Cause” means a determination by two-thirds of the Board that Employee:

(1)willfully and continually failed to substantially perform Employee’s duties to the Partnership and its Affiliates (other than a failure resulting from Employee’s Disability);

(2)willfully engaged in conduct that is demonstrably and materially injurious to the Partnership, the General Partner or any of their respective Affiliates, monetarily or otherwise;

(3)has been convicted of, or has plead guilty or nolo contendere to, a misdemeanor involving moral turpitude or a felony;

(4)has committed an act of fraud, or material embezzlement or material theft, in each case, in the course of Employee’s employment relationship with the Employer or one of its Affiliates, or

(5)has materially breached any obligations of Employee under any written agreement (including any non-compete, non-solicitation or confidentiality covenants) entered into between Employee and the Partnership, the General Partner or any of their respective Affiliates.

Notwithstanding the foregoing, except for a failure, breach or refusal that, by its nature, cannot reasonably be expected to be cured, Employee shall have 30 days following the delivery of written notice by the Employer or one of its Affiliates within which to cure any actions or omissions described in clauses (1), (2), (4) or (5) constituting Cause; providedhowever, that, if the Employer reasonably expects irreparable injury from a delay of 30 days, the Employer or one of its Affiliates may give Employee notice of such shorter period within which to cure as is reasonable under the circumstances, which may include the termination of Employee’s employment without notice and with immediate effect.

(ii)“Disability” means Employee’s incapacity, due to accident, sickness or another circumstance that renders Employee unable to perform the essential functions of Employee’s job function, with reasonable accommodation, for a period of at least 90 consecutive days or 120 days in any 12-month period.

(iii)“Good Reason” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Good Reason,” then “Good

Exhibit A-3

Reason” means the occurrence of any of the following events without Employee’s written consent:

(1)a reduction in Employee’s total compensation other than a general reduction in compensation that affects all similarly situated employees in substantially the same proportions;

(2)a relocation of Employee’s principal place of employment by more than 50 miles from the location of Employee’s principal place of employment as of the Date of Grant;

(3)any material breach by the Partnership or the General Partner of any material provision of this Agreement;

(4)a material, adverse change in Employee’s title, authority, duties or responsibilities (other than while Employee has a Disability);

(5)a material adverse change in the reporting structure applicable to Employee; or

(6)following a Change of Control, either (x) a failure of the General Partner or one of its Affiliates to continue in effect any benefit plan or compensation arrangement in which Employee was participating immediately prior to such Change of Control or (y) the taking of any action by the General Partner or one of its Affiliates that adversely affects Employee’s participation in, or materially reduces Employee’s benefits or compensation under, any such benefit plan or compensation arrangement, unless, in the case of either clause (x) or (y), there is substituted a comparable benefit plan or compensation arrangement that is at least economically equivalent to the benefit plan or compensation arrangement being terminated or in which Employee’s participation is being adversely affected or Employee’s benefits or compensation are being materially reduced.

Notwithstanding the foregoing provisions of this definition or any other provision of the Agreement to the contrary, any assertion by Employee of a termination for Good Reason shall not be effective unless all of the following conditions are satisfied: (A) Employee must provide written notice to the General Partner of the existence of the condition(s) providing grounds for termination for Good Reason within 30 days of the initial existence of such grounds; (B) the condition(s) specified in such notice must remain uncorrected for 30 days following the General Partner’s receipt of such written notice; and (C) the date of Employee’s termination of employment must occur within 60 days after the initial existence of the condition(s) specified in such notice.

Exhibit A-4

(iv)“Qualifying Termination” means a termination of Employee’s employment (1) by the Employer without Cause or (2) as a result of Employee’s resignation for Good Reason.

3.Settlement of Performance Units. As soon as administratively practicable following the Committee’s determination of the level of achievement of the Performance Goals for the Performance Period, but in no event later than March 15 following the end of such Performance Period, Employee (or Employee’s permitted transferee, if applicable) shall be issued a number of Common Units equal to the number of Performance Units subject to this Award that become earned based on the level of achievement of the Performance Goals as determined by the Committee in accordance with Section 2. Any fractional Performance Unit that becomes earned hereunder will be rounded down to the next whole Performance Unit if it is less than 0.5 and rounded up to the next whole Performance Unit if it is 0.5 or more. No fractional Common Units, nor the cash value of any fractional Common Units, will be issuable or payable to Employee pursuant to this Agreement. All Common Units issued hereunder shall be delivered either by delivering one or more certificates for such Common Units to Employee or by entering such Common Units in book-entry form, as determined by the Committee in its sole discretion. The value of Common Units shall not bear any interest owing to the passage of time. Neither this Section 3 nor any action taken pursuant to or in accordance with this Agreement shall be construed to create a trust or a funded or secured obligation of any kind.

4.DERs. Each Performance Unit subject to this Award is hereby granted in tandem with a corresponding DER. Each DER granted hereunder shall remain outstanding from the Date of Grant until the earlier of the settlement or forfeiture of the Performance Unit to which it corresponds (the “DER Period”). If a Common Unit is issued pursuant to Section 3 in settlement of a Performance Unit that becomes earned, then, as soon as administratively practicable following the issuance of such Common Unit, but in no event later than 60 days after the date such Performance Unit becomes earned, the General Partner shall issue to Employee, with respect to the DER corresponding to the earned Performance Unit settled by the issuance of such Common Unit, additional Common Units with a value at the time of issuance equal to the aggregate amount of cash distributions that would have been paid to Employee if Employee were the record owner of the Common Unit issued to Employee in settlement of Employee’s Performance Units as of the applicable record date for each cash distribution paid by the Partnership during the DER Period applicable to such Performance Unit. DERs shall not entitle Employee to any payments relating to distributions paid after the earlier to occur of the applicable Performance Unit settlement date or the forfeiture of the Performance Unit underlying such DER.

5.Rights as Unitholder.  Neither Employee nor any person claiming under or through Employee shall have any of the rights or privileges of a holder of Common Units in respect of any Common Units that may become deliverable hereunder unless and until certificates representing such Common Units have been issued or recorded in book entry form on the records of the Partnership or its transfer agents or registrars, and delivered in certificate or book entry form to Employee or any person claiming under or through Employee.

Exhibit A-5

6.Tax Withholding. Upon any taxable event arising in connection with the Performance Units or the DERs, the General Partner shall have the authority and the right to deduct or withhold (or cause the Employer or one of its Affiliates to deduct or withhold), or to require Employee to remit to the General Partner (or the Employer or one of its Affiliates), an amount sufficient to satisfy all applicable federal, state and local taxes required by law to be withheld with respect to such event. In satisfaction of the foregoing requirement, unless otherwise determined by the Committee, the General Partner or the Employer or one of its Affiliates shall withhold from any cash or equity remuneration (including, if applicable, any of the Common Units otherwise deliverable under this Agreement) then or thereafter payable to Employee an amount equal to the aggregate amount of taxes required to be withheld with respect to such event. If such tax obligations are satisfied through the withholding or surrender of Common Units pursuant to this Agreement, the maximum number of Common Units that may be so withheld (or surrendered) shall be the number of Common Units that have an aggregate Fair Market Value on the date of withholding (or surrender) equal to the aggregate amount of taxes required to be withheld, determined based on the greatest withholding rates for federal, state, local and foreign income tax and payroll tax purposes that may be utilized without resulting in adverse accounting, tax or other consequences to the General Partner or any of its Affiliates (other than immaterial administrative, reporting or similar consequences), as determined by the Committee. Employee acknowledges and agrees that none of the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates have made any representation or warranty as to the tax consequences to Employee as a result of the receipt of the Performance Units and the DERs, the earning of the Performance Units and the DERs or the forfeiture of any of the Performance Units and the DERs. Employee represents that he is in no manner relying on the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates or any of their respective managers, directors, officers, employees or authorized representatives (including, without limitation, attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial representatives) for tax advice or an assessment of such tax consequences. Employee represents that he has consulted with any tax consultants that Employee deems advisable in connection with the Performance Units and the DERs.

7.Refusal to Transfer; Stop-Transfer Notices.  The Partnership shall not be required (a) to transfer on its books any Common Units that have been sold or otherwise transferred in violation of any of the provisions of this Agreement or (b) to treat as owner of such Common Units or to accord the right to vote or pay distributions to any purchaser or other transferee to whom such Common Units shall have been so transferred.  Employee agrees that, in order to ensure compliance with the restrictions referred to herein, the Partnership or the General Partner may issue appropriate “stop transfer” instructions to its transfer agent, if any, and that, if the Partnership transfers its own securities, it may make appropriate notations to the same effect in its own records.

8.Non-Transferability.  None of the Performance Units, the DERs or any interest or right therein shall be (a) sold, pledged, assigned or transferred in any manner during the lifetime of Employee other than by will or the laws of descent and distribution, unless and until

Exhibit A-6

the Common Units underlying the Performance Units have been issued, and all restrictions applicable to such Common Units have lapsed, or (b) liable for the debts, contracts or engagements of Employee or his or her successors in interest. Except to the extent expressly permitted by the preceding sentence, any purported sale, pledge, assignment, transfer, attachment or encumbrance of the Performance Units, the DERs or any interest or right therein shall be null, void and unenforceable against the Partnership, the General Partner, the Employer and their respective Affiliates.

9.Compliance with Securities Law. Notwithstanding any provision of this Agreement to the contrary, the issuance of Common Units hereunder will be subject to compliance with all applicable requirements of applicable law with respect to such securities and with the requirements of any securities exchange or market system upon which the Common Units may then be listed. No Common Units will be issued hereunder if such issuance would constitute a violation of any applicable law or regulation or the requirements of any securities exchange or market system upon which the Common Units may then be listed. In addition, Common Units will not be issued hereunder unless (a) a registration statement under the Securities Act of 1933, as amended (the “Securities Act”) is in effect at the time of such issuance with respect to the Common Units to be issued or (b) in the opinion of legal counsel to the Partnership, the Common Units to be issued are permitted to be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Partnership to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Partnership’s legal counsel to be necessary for the lawful issuance and sale of any Common Units hereunder will relieve the Partnership of any liability in respect of the failure to issue such Common Units as to which such requisite authority has not been obtained. As a condition to any issuance of Common Units hereunder, the General Partner or the Partnership may require Employee to satisfy any requirements that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the General Partner or the Partnership.

10.No Right to Continued Employment or Awards.

(a)For purposes of this Agreement, Employee shall be considered to be employed by the Employer as long as Employee remains an “Employee” (as such term is defined in the Plan), or an employee of a corporation or other entity (or a parent or subsidiary of such corporation or other entity) assuming or substituting a new award for this Award. Without limiting the scope of the preceding sentence, it is specifically provided that Employee shall be considered to have terminated employment at the time of the termination of the status of the entity or other organization that employs Employee as an “Affiliate” of the General Partner. Nothing in the adoption of the Plan, nor the award of the Performance Units or DERs thereunder pursuant to the Grant Notice and this Agreement, shall confer upon Employee the right to continued employment by, or a continued service relationship with, the Employer or any of its Affiliates, or any other entity, or affect in any way the right of the Employer or any such Affiliate, or any other entity to terminate such employment at any time. Unless otherwise

Exhibit A-7

provided in a written employment agreement or by applicable law, Employee’s employment by the Employer, or any such Affiliate, or any other entity shall be on an at-will basis, and the employment relationship may be terminated at any time by either Employee or the Employer, or any such Affiliate, or other entity for any reason whatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of such employment, and the cause of such termination, shall be determined by the Committee or its delegate, and such determination shall be final, conclusive and binding for all purposes.

(b)The grant of the Performance Units and DERs is a one-time Award and does not create any contractual or other right to receive a grant of Awards or benefits in lieu of Awards in the future. Future Awards will be at the sole discretion of the Committee.

11.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of Employee, such notices or communications shall be effectively delivered if hand delivered to Employee at Employee’s principal place of employment or if sent by registered or certified mail to Employee at the last address Employee has filed with the Employer. In the case of the Partnership or General Partner, such notices or communications shall be effectively delivered if sent by registered or certified mail to the General Partner at its principal executive offices.

12.Agreement to Furnish Information. Employee agrees to furnish to the General Partner all information requested by the General Partner to enable the General Partner or any of its Affiliates to comply with any reporting or other requirement imposed upon the General Partner or any of its Affiliates by or under any applicable statute or regulation.

13.Entire Agreement; Amendment. This Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the Performance Units and DERs granted hereunder; provided, however, that the terms of this Agreement shall not modify and shall be subject to the terms and conditions of any employment and/or severance agreement between the Partnership, the General Partner, the Employer or any of their respective Affiliates and Employee in effect as of the date a determination is to be made under this Agreement. Without limiting the scope of the preceding sentence, except as provided therein, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. The Committee may, in its sole discretion, amend this Agreement from time to time in any manner that is not inconsistent with the Plan; provided, however, that except as otherwise provided in the Plan or this Agreement, any such amendment that materially reduces the rights of Employee shall be effective only if it is in writing and signed by both Employee and an authorized officer of the General Partner.

14.Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of law principles thereof.

Exhibit A-8

15.Successors and Assigns. The General Partner may assign any of its rights under this Agreement without Employee’s consent. This Agreement will be binding upon and inure to the benefit of the successors and assigns of the General Partner. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement will be binding upon Employee and Employee's beneficiaries, executors, administrators and the person(s) to whom the Performance Units or DERs may be transferred by will or the laws of descent or distribution.

16.Clawback. Notwithstanding any provision in this Agreement or the Grant Notice to the contrary, to the extent required by (a) applicable law, including, without limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards and/or (b) any policy that may be adopted or amended by the Board from time to time, all Common Units issued hereunder shall be subject to forfeiture, repurchase, recoupment and/or cancellation to the extent necessary to comply with such law(s) and/or policy.

17.Severability. If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of such provision shall not affect the validity or enforceability of any other provision of this Agreement and all other provisions shall remain in full force and effect.

18.Code Section 409A. None of the Performance Units, DERs or any amounts payable pursuant to this Agreement are intended to constitute or provide for a deferral of compensation that is subject to Section 409A of the Code and the Treasury regulations and other interpretive guidance issued thereunder (collectively, “Section 409A”). Nevertheless, to the extent that the Committee determines that the Performance Units or DERs may not be exempt from Section 409A, then, if Employee is deemed to be a “specified employee” within the meaning of Section 409A, as determined by the Committee, at a time when Employee becomes eligible for settlement of the Performance Units or DERs upon his “separation from service” within the meaning of Section 409A, then to the extent necessary to prevent any accelerated or additional tax under Section 409A, such settlement will be delayed until the earlier of: (a) the date that is six months following Employee’s separation from service and (b) Employee’s death. Notwithstanding the foregoing, none of the Partnership, the General Partner, the Employer or any of their respective Affiliates makes any representations that the payments provided under this Agreement are exempt from or compliant with Section 409A and in no event shall the Partnership, the General Partner, the Employer or any of their respective Affiliates be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by Employee on account of non-compliance with Section 409A.

Remainder of Page Intentionally Blank

Exhibit A-9

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

pursuant to Rule 13a-14(a) and Rule 15d-14(a)

of the Securities Exchange Act of 1934, as amended

I, Thomas L. Carter, Jr., certify that:

1. I have reviewed this report on Form 10-Q of Black Stone Minerals, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2024	/s/ Thomas L. Carter, Jr.
	Thomas L. Carter, Jr.
	Chief Executive Officer
	Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

pursuant to Rule 13a-14(a) and Rule 15d-14(a)

of the Securities Exchange Act of 1934, as amended

I, Evan M. Kiefer, certify that:

1. I have reviewed this report on Form 10-Q of Black Stone Minerals, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2024	/s/ Evan M. Kiefer
	Evan M. Kiefer
	Chief Financial Officer
	Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

EX-32.1

Exhibit 32.1

Certification of

Chief Executive Officer and Chief Financial Officer

under Section 906 of the

Sarbanes Oxley Act of 2002, 18 U.S.C. § 1350

In connection with the report on Form 10-Q of Black Stone Minerals, L.P. (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Thomas L. Carter, Jr., Chief Executive Officer of the Partnership, and Evan M. Kiefer, Chief Financial Officer of the Partnership, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 7, 2024	/s/ Thomas L. Carter, Jr.
	Thomas L. Carter, Jr. Chief Executive Officer Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.
Date: May 7, 2024	/s/ Evan M. Kiefer
	Evan M. Kiefer Chief Financial Officer Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

XML

COVER - shares	3 Months Ended
	Mar. 31, 2024	May 03, 2024
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 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	Q1
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Common units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		210,702,620
Preferred Units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
CURRENT ASSETS
Cash and cash equivalents	$ 40,456	$ 70,282
Accounts receivable	72,428	82,253
Commodity derivative assets	30,741	38,273
Prepaid expenses and other current assets	2,540	2,319
TOTAL CURRENT ASSETS	146,165	193,127
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $913,031 and $890,338 at March 31, 2024 and December 31, 2023, respectively	3,049,455	3,026,394
Accumulated depreciation, depletion, amortization, and impairment	(1,972,524)	(1,961,899)
Oil and natural gas properties, net	1,076,931	1,064,495
Other property and equipment, net of accumulated depreciation of $14,270 and $14,163 at March 31, 2024 and December 31, 2023, respectively	938	1,007
NET PROPERTY AND EQUIPMENT	1,077,869	1,065,502
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,641	8,255
TOTAL ASSETS	1,231,675	1,266,884
CURRENT LIABILITIES
Accounts payable	5,844	6,270
Accrued liabilities	7,380	17,003
Commodity derivative liabilities	12,782	1,229
Other current liabilities	1,374	1,334
TOTAL CURRENT LIABILITIES	27,380	25,836
LONG–TERM LIABILITIES
Accrued incentive compensation	802	1,699
Commodity derivative liabilities	5,858	81
Asset retirement obligations	19,078	19,030
Other long-term liabilities	2,755	2,893
TOTAL LIABILITIES	55,873	49,539
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY
Partners' equity – general partner interest	0	0
TOTAL EQUITY	875,324	918,208
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,231,675	1,266,884
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2024 and December 31, 2023	300,478	299,137
Common units
EQUITY
Partners' equity – common units, 210,656 and 209,991 units outstanding at March 31, 2024 and December 31, 2023, respectively	$ 875,324	$ 918,208

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Unproved properties	$ 913,031	$ 890,338
Accumulated depreciation	$ 14,270	$ 14,163
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711,000	14,711,000
Common units
Partners' equity - units, outstanding (in shares)	210,656,000	209,991,000

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
REVENUE
Revenue from contracts with customers	$ 116,783	$ 122,307
Gain (loss) on commodity derivative instruments	(11,290)	52,271
TOTAL REVENUE	105,493	174,578
OPERATING (INCOME) EXPENSE
Lease operating expense	2,432	2,668
Production costs and ad valorem taxes	13,038	12,667
Exploration expense	3	4
Depreciation, depletion, and amortization	11,639	11,147
General and administrative	14,090	12,648
Accretion of asset retirement obligations	317	245
TOTAL OPERATING EXPENSE	41,519	39,379
INCOME (LOSS) FROM OPERATIONS	63,974	135,199
OTHER INCOME (EXPENSE)
Interest and investment income	670	157
Interest expense	(629)	(814)
Other income (expense)	(88)	(99)
TOTAL OTHER EXPENSE	(47)	(756)
NET INCOME (LOSS)	63,927	134,443
Distributions on Series B cumulative convertible preferred units	(7,367)	(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,560	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	56,560	129,193
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 56,560	$ 129,193
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.27	$ 0.62
Per common unit (diluted) (in dollars per share)	$ 0.27	$ 0.60
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic) (in shares)	210,654	209,941
Weighted average common units outstanding (diluted) (in shares)	210,654	224,910
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 71,224	$ 60,909
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	42,011	57,423
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 3,548	$ 3,975

XML

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, 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
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		$ 875,324

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 63,927	$ 134,443
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	11,639	11,147
Accretion of asset retirement obligations	317	245
Amortization of deferred charges	268	255
(Gain) loss on commodity derivative instruments	11,290	(52,271)
Net cash (paid) received on settlement of commodity derivative instruments	13,797	13,285
Equity-based compensation	2,383	2,118
Changes in operating assets and liabilities:
Accounts receivable	9,851	41,588
Prepaid expenses and other current assets	(220)	(182)
Accounts payable, accrued liabilities, and other	(8,510)	(13,333)
Settlement of asset retirement obligations	(282)	(140)
NET CASH PROVIDED BY OPERATING ACTIVITIES	104,460	137,155
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(22,966)	0
Additions to oil and natural gas properties	(285)	(1,932)
Additions to oil and natural gas properties leasehold costs	(753)	0
Purchases of other property and equipment	(39)	(22)
Proceeds from the sale of oil and natural gas properties	79	0
NET CASH USED IN INVESTING ACTIVITIES	(23,964)	(1,954)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility	6,000	50,000
Repayments under credit facility	(6,000)	(60,000)
Debt issuance costs and other	(16)	(12)
NET CASH USED IN FINANCING ACTIVITIES	(110,322)	(120,358)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(29,826)	14,843
CASH AND CASH EQUIVALENTS – beginning of the period	70,282	4,307
CASH AND CASH EQUIVALENTS – end of the period	40,456	19,150
SUPPLEMENTAL DISCLOSURE
Interest paid	361	588
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(99,899)	(99,600)
Repurchases of common units	(4,381)	(5,496)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (6,026)	$ (5,250)

XML

BUSINESS AND BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 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 three months ended March 31, 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 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 three months ended March 31, 2024.

Accounts Receivable

The following table presents information about the Partnership's accounts receivable:

	March 31, 2024		December 31, 2023
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	68,312	$	77,560
Other	4,116		4,693
Total accounts receivable	$	72,428	$	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.

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OIL AND NATURAL GAS PROPERTIES

3 Months Ended

Mar. 31, 2024

Extractive Industries [Abstract]

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES    

Divestitures

The Partnership had no material divestiture activity during 2023 or the three months ended March 31, 2024.

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 first quarter of 2024, the Partnership acquired mineral and royalty interests that consisted of substantially all unproved oil and natural gas properties from various sellers for cash consideration of $23.0 million, including capitalized direct transaction costs. These acquisitions were considered asset acquisitions, were primarily located in the Gulf Coast land region, and were funded with cash from operating activities.

During the year ended December 31, 2023, the Partnership acquired mineral and royalty interests that consisted of unproved oil and natural gas properties from various sellers for cash consideration of $14.6 million, including capitalized direct transaction costs. These acquisitions were considered asset acquisitions, were primarily located in the Gulf Coast land region, and were funded with cash from operating activities.

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 portions of the Partnership's undeveloped acreage in San Augustine County, Texas. 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 March 31, 2024, 20 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, BSM and Aethon entered into an agreement to develop certain portions of the Partnership's undeveloped acreage 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 March 31, 2024, 45 wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

Aethon Time-Out

In December 2023, the Partnership received notice that Aethon was exercising the "time-out" provisions under its joint exploration agreements with BSM in Angelina and San Augustine counties in East Texas. When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. The current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months. Aethon has not previously invoked the time-out provisions under the agreements.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

The Partnership did not recognize any impairment of oil and natural gas properties for the three months ended March 31, 2024 and 2023. See "Note 5 - Fair Value Measurements" for additional information.

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 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 March 31, 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:

		March 31, 2024
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	36,665	$	(5,924)	$	30,741
Long-term asset	Deferred charges and other long-term assets	512		(365)		147
Total assets		$	37,177	$	(6,289)	$	30,888
Liabilities:
Current liability	Commodity derivative liabilities	$	18,706	$	(5,924)	$	12,782
Long-term liability	Commodity derivative liabilities	6,223		(365)		5,858
Total liabilities		$	24,929	$	(6,289)	$	18,640

		December 31, 2023
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	41,485	$	(3,212)	$	38,273
Long-term asset	Deferred charges and other long-term assets	498		(126)		372
Total assets		$	41,983	$	(3,338)	$	38,645
Liabilities:
Current liability	Commodity derivative liabilities	$	4,441	$	(3,212)	$	1,229
Long-term liability	Commodity derivative liabilities	207		(126)		81
Total liabilities		$	4,648	$	(3,338)	$	1,310

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 March 31,
Derivatives not designated as hedging instruments	2024		2023
	(in thousands)
Beginning fair value of commodity derivative instruments	$	37,335	$	28,941
Gain (loss) on oil derivative instruments	(23,230)		7,422
Gain (loss) on natural gas derivative instruments	11,940		44,849
Net cash paid (received) on settlements of oil derivative instruments	(121)		1,400
Net cash paid (received) on settlements of natural gas derivative instruments	(13,676)		(14,685)
Net change in fair value of commodity derivative instruments	(25,087)		38,986
Ending fair value of commodity derivative instruments	$	12,248	$	67,927

The Partnership had the following open derivative contracts for oil as of March 31, 2024:

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2024
First Quarter	190,000	$	71.45	$	67.00	$	81.00
Second Quarter	570,000	71.45		67.00		81.00
Third Quarter	570,000	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

The Partnership had the following open derivative contracts for natural gas as of March 31, 2024:

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2024
Second Quarter	10,465,000	$	3.55	$	3.00	$	3.76
Third Quarter	10,580,000	3.55		3.00		3.76
Fourth Quarter	10,580,000	3.55		3.00		3.76
2025
First Quarter	7,200,000	$	3.39	$	3.34	$	3.65
Second Quarter	7,280,000	3.39		3.34		3.65
Third Quarter	11,040,000	3.45		3.34		3.65
Fourth Quarter	11,040,000	3.45		3.34		3.65

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 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 three months ended March 31, 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 March 31, 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 March 31, 2024
Financial Assets
Commodity derivative instruments	$	—	$	37,177	$	—	$	(6,289)	$	30,888
Financial Liabilities
Commodity derivative instruments	$	—	$	24,929	$	—	$	(6,289)	$	18,640
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 three months ended March 31, 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 March 31, 2024 or December 31, 2023. There were no assets measured at fair value on a non-recurring basis for the three months ended March 31, 2024 or the year ended December 31, 2023.

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CREDIT FACILITY

3 Months Ended

Mar. 31, 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. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2024.

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, (2) 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 March 31, 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 7.92% during the three months ended March 31, 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 March 31, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.

There was no aggregate principal balance outstanding at March 31, 2024 and December 31, 2023, respectively. The unused portion of the available borrowings under the Credit Facility was $375.0 million at March 31, 2024 and December 31, 2023

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 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 March 31, 2024 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

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INCENTIVE COMPENSATION

3 Months Ended

Mar. 31, 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 March 31,
	2024		2023
	(in thousands)
Cash—short and long-term incentive plans	$	1,260	$	1,079
Equity-based compensation—restricted common units	996		954
Equity-based compensation—restricted performance units	738		633
Board of Directors incentive plan	649		531
Total incentive compensation expense	$	3,643	$	3,197

For the three months ended March 31, 2024, the Partnership repurchased 286,761 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.

In the first quarter of 2022, the board of directors of the Partnership's general partner (the "Board") approved a grant of awards to all employees dependent on the achievement of an aspirational production target to be measured in the fourth quarter of 2025 (the "Aspirational Awards"). The Aspirational Awards include performance cash awards and performance equity awards in the form of restricted performance units. To the extent earned, each performance unit represents the right to receive one common unit. The performance cash awards and performance units are eligible to become earned at the end of the requisite service period on December 31, 2025 if the minimum performance metrics are achieved. The minimum performance metrics are at least 42 Mboe per day of average daily royalty production in either the fourth quarter or the month of December of 2025 while maintaining a net debt to EBITDA ratio less than or equal to 1.0 on December 31, 2025. Average daily royalty production does not include production attributable to acquisitions consummated during the performance period. Compensation expense related to the Aspirational Awards will be recorded over the service period when achievement of the performance condition is probable. Total compensation expense to be recognized over the life of the Aspirational Awards consists of $5.6 million for the performance cash awards and $14.7 million for the performance equity awards (1,220,201 performance units with a weighted-average grant date fair value of $12.03 per unit). As of March 31, 2024, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

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PREFERRED UNITS

3 Months Ended

Mar. 31, 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 March 31, 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.

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EARNINGS PER UNIT

3 Months Ended

Mar. 31, 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 March 31,
	2024		2023
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	63,927	$	134,443
Distributions on Series B cumulative convertible preferred units	(7,367)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	56,560	$	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	56,560		129,193
	$	56,560	$	129,193
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders	$	56,560	$	129,193
Effect of dilutive securities	—		5,250
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$	56,560	$	134,443
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)	210,654		209,941
Effect of dilutive securities	—		14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	210,654		224,910
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.27	$	0.62
Per common unit (diluted)	$	0.27	$	0.60

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 March 31,
	2024	2023
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	15,072	—

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COMMON UNITS

3 Months Ended

Mar. 31, 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, 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 March 31,
	2024		2023
Distributions declared and paid per common unit	$	0.4750	$	0.4750

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 three months ended March 31, 2024. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.

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SUBSEQUENT EVENTS

3 Months Ended

Mar. 31, 2024

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS    

Distribution

On April 17, 2024, the Board approved a distribution for the three months ended March 31, 2024 of $0.375 per common unit. Distributions will be payable on May 17, 2024 to unitholders of record at the close of business on May 10, 2024.

Acquisitions

Subsequent to March 31, 2024, the Partnership acquired mineral and royalty interests from various sellers for cash consideration of $12.3 million. These acquisitions were funded with cash from operating activities.

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Insider Trading Arrangements	3 Months Ended
	Mar. 31, 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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 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 three months ended March 31, 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Tables)

3 Months Ended

Mar. 31, 2024

Accounting Policies [Abstract]

Schedule of Accounts Receivable

The following table presents information about the Partnership's accounts receivable:

	March 31, 2024		December 31, 2023
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	68,312	$	77,560
Other	4,116		4,693
Total accounts receivable	$	72,428	$	82,253

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OIL AND NATURAL GAS PROPERTIES (Tables)

3 Months Ended

Mar. 31, 2024

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	%

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2024

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:

		March 31, 2024
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	36,665	$	(5,924)	$	30,741
Long-term asset	Deferred charges and other long-term assets	512		(365)		147
Total assets		$	37,177	$	(6,289)	$	30,888
Liabilities:
Current liability	Commodity derivative liabilities	$	18,706	$	(5,924)	$	12,782
Long-term liability	Commodity derivative liabilities	6,223		(365)		5,858
Total liabilities		$	24,929	$	(6,289)	$	18,640

		December 31, 2023
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	41,485	$	(3,212)	$	38,273
Long-term asset	Deferred charges and other long-term assets	498		(126)		372
Total assets		$	41,983	$	(3,338)	$	38,645
Liabilities:
Current liability	Commodity derivative liabilities	$	4,441	$	(3,212)	$	1,229
Long-term liability	Commodity derivative liabilities	207		(126)		81
Total liabilities		$	4,648	$	(3,338)	$	1,310

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 March 31,
Derivatives not designated as hedging instruments	2024		2023
	(in thousands)
Beginning fair value of commodity derivative instruments	$	37,335	$	28,941
Gain (loss) on oil derivative instruments	(23,230)		7,422
Gain (loss) on natural gas derivative instruments	11,940		44,849
Net cash paid (received) on settlements of oil derivative instruments	(121)		1,400
Net cash paid (received) on settlements of natural gas derivative instruments	(13,676)		(14,685)
Net change in fair value of commodity derivative instruments	(25,087)		38,986
Ending fair value of commodity derivative instruments	$	12,248	$	67,927

Summary of Open Derivative Contracts

The Partnership had the following open derivative contracts for oil as of March 31, 2024:

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2024
First Quarter	190,000	$	71.45	$	67.00	$	81.00
Second Quarter	570,000	71.45		67.00		81.00
Third Quarter	570,000	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

The Partnership had the following open derivative contracts for natural gas as of March 31, 2024:

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2024
Second Quarter	10,465,000	$	3.55	$	3.00	$	3.76
Third Quarter	10,580,000	3.55		3.00		3.76
Fourth Quarter	10,580,000	3.55		3.00		3.76
2025
First Quarter	7,200,000	$	3.39	$	3.34	$	3.65
Second Quarter	7,280,000	3.39		3.34		3.65
Third Quarter	11,040,000	3.45		3.34		3.65
Fourth Quarter	11,040,000	3.45		3.34		3.65

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2024
Financial Assets
Commodity derivative instruments	$	—	$	37,177	$	—	$	(6,289)	$	30,888
Financial Liabilities
Commodity derivative instruments	$	—	$	24,929	$	—	$	(6,289)	$	18,640
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

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INCENTIVE COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2024

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 March 31,
	2024		2023
	(in thousands)
Cash—short and long-term incentive plans	$	1,260	$	1,079
Equity-based compensation—restricted common units	996		954
Equity-based compensation—restricted performance units	738		633
Board of Directors incentive plan	649		531
Total incentive compensation expense	$	3,643	$	3,197

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EARNINGS PER UNIT (Tables)

3 Months Ended

Mar. 31, 2024

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 March 31,
	2024		2023
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	63,927	$	134,443
Distributions on Series B cumulative convertible preferred units	(7,367)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	56,560	$	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	56,560		129,193
	$	56,560	$	129,193
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders	$	56,560	$	129,193
Effect of dilutive securities	—		5,250
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$	56,560	$	134,443
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)	210,654		209,941
Effect of dilutive securities	—		14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	210,654		224,910
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.27	$	0.62
Per common unit (diluted)	$	0.27	$	0.60

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 March 31,
	2024	2023
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	15,072	—

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COMMON UNITS (Tables)

3 Months Ended

Mar. 31, 2024

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 March 31,
	2024		2023
Distributions declared and paid per common unit	$	0.4750	$	0.4750

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BUSINESS AND BASIS OF PRESENTATION - Narrative (Details)	3 Months Ended
	Mar. 31, 2024 segment state
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20.00%
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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 72,428	$ 82,253
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	68,312	77,560
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 4,116	$ 4,693

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OIL AND NATURAL GAS PROPERTIES - Acquisitions (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Asset Acquisition [Line Items]
Aggregate cash consideration	$ 22,966	$ 0
Unproved Oil And Gas Properties
Asset Acquisition [Line Items]
Total consideration			$ 14,600
Mineral and Royalty Acreage
Asset Acquisition [Line Items]
Aggregate cash consideration	$ 23,000

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OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details)	1 Months Ended		3 Months Ended				12 Months Ended
	May 31, 2021	Nov. 30, 2020	Mar. 31, 2024 USD ($) well	Mar. 31, 2023 USD ($)	Sep. 30, 2021 well	Sep. 30, 2020 well	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
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			20
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
% of Partnership's Working Interest		100.00%
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		25.00%

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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	100.00%
Maximum % on an 8/8ths basis	50.00%
Other
Asset Acquisition [Line Items]
% of Partnership's Working Interest	100.00%
Maximum % on an 8/8ths basis	25.00%
Canaan | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	64.00%
Canaan | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	32.00%
Canaan | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	40.00%
Maximum % on an 8/8ths basis	10.00%
Azul | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	20.00%
Azul | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	10.00%
Azul | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	50.00%
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	16.00%
JWM | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	8.00%
JWM | San Augustine County, Texas | Other | Farmout Agreement
Asset Acquisition [Line Items]
% of Partnership's Working Interest	10.00%
JWM | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Maximum % on an 8/8ths basis	2.50%

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details)	Mar. 31, 2024 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	7

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 37,177	$ 41,983
Effect of counterparty netting, assets	(6,289)	(3,338)
Total net carrying value on balance sheet, assets	30,888	38,645
Gross fair value, liabilities	24,929	4,648
Effect of counterparty netting, liabilities	(6,289)	(3,338)
Total net carrying value on balance sheet, liabilities	18,640	1,310
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	36,665	41,485
Effect of counterparty netting, assets	(5,924)	(3,212)
Total net carrying value on balance sheet, assets	30,741	38,273
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	512	498
Effect of counterparty netting, assets	(365)	(126)
Total net carrying value on balance sheet, assets	147	372
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	18,706	4,441
Effect of counterparty netting, liabilities	(5,924)	(3,212)
Total net carrying value on balance sheet, liabilities	12,782	1,229
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	6,223	207
Effect of counterparty netting, liabilities	(365)	(126)
Total net carrying value on balance sheet, liabilities	$ 5,858	$ 81

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (11,290)	$ 52,271
Net cash paid (received) on settlements of derivative instruments	(13,797)	(13,285)
Derivatives not designated as hedging instruments
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	37,335	28,941
Net change in fair value of commodity derivative instruments	(25,087)	38,986
Ending fair value of commodity derivative instruments	12,248	67,927
Derivatives not designated as hedging instruments | Oil Swap Contracts:
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(23,230)	7,422
Net cash paid (received) on settlements of derivative instruments	(121)	1,400
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	11,940	44,849
Net cash paid (received) on settlements of derivative instruments	$ (13,676)	$ (14,685)

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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	3 Months Ended
	Mar. 31, 2024 MMBTU $ / MMBTU $ / bbl bbl
Oil Swap Contracts: | First 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)	67.00
Derivative contract, price range high (in USD per Bbl or MMBtu)	81.00
Oil Swap Contracts: | Second 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)	67.00
Derivative contract, price range high (in USD per Bbl or MMBtu)	81.00
Oil Swap Contracts: | Third 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)	67.00
Derivative contract, price range high (in USD per Bbl or MMBtu)	81.00
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)	67.00
Derivative contract, price range high (in USD per Bbl or MMBtu)	81.00
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
Natural gas and natural gas liquids sales | Second Quarter 2024
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	10,465
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	3.00
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU	3.76
Natural gas and natural gas liquids sales | Third 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	3.00
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU	3.76
Natural gas and natural gas liquids sales | 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	3.00
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / MMBTU	3.76
Natural gas and natural gas liquids sales | First Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	7,200
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU	3.39
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 and natural gas liquids sales | Second Quarter 2025
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	7,280
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU	3.39
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 and natural gas liquids sales | 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 and natural gas liquids sales | 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

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FAIR VALUE MEASUREMENTS - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 37,177	$ 41,983
Effect of counterparty netting, assets	(6,289)	(3,338)
Total net carrying value on balance sheet, assets	30,888	38,645
Gross fair value, liabilities	24,929	4,648
Effect of counterparty netting, liabilities	(6,289)	(3,338)
Total net carrying value on balance sheet, liabilities	18,640	1,310
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	(6,289)	(3,338)
Total net carrying value on balance sheet, assets	30,888	38,645
Effect of counterparty netting, liabilities	(6,289)	(3,338)
Total net carrying value on balance sheet, liabilities	18,640	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	37,177	41,983
Gross fair value, liabilities	24,929	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

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CREDIT FACILITY (Details) $ in Millions	1 Months Ended	3 Months Ended
	Dec. 31, 2023 USD ($)	Mar. 31, 2024 USD ($) lender	Oct. 31, 2023 USD ($)	Oct. 30, 2023 USD ($)	Apr. 30, 2023 USD ($)
Line Of Credit Facility [Line Items]
Number of lenders | lender		0.667
Percentage current borrowing base		5.00%
Current ratio		1.0
Senior Line of Credit | Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity		$ 1,000.0
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (percent)		10.00%
Borrowing base			$ 580.0		$ 550.0
Increase limit				$ 375.0	$ 375.0
Weighted average interest rate (percent)	7.36%	7.92%
Interest payable, term		90 days
Percentage of availability of lenders' commitments, distributions not permitted		10.00%
Ratio of total debt to EBITDAX, distributions not permitted		3.0
Unused portion of current borrowing base	$ 375.0	$ 375.0
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 SOFR
Line Of Credit Facility [Line Items]
Interest rate (percent)		0.10%
Senior Line of Credit | Revolving Credit Facility | Adjusted Term Secured Overnight Funds Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		1.00%
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		1.0
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%

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INCENTIVE COMPENSATION - Summary of Incentive Compensation Expense (Details) $ / shares in Units, MMBoe in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2024 USD ($) MMBoe commonUnit $ / shares shares	Mar. 31, 2023 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 0
Number of common units receivable | commonUnit	1
Mboe per day | MMBoe	42
Current ratio	1.0
Common units | November 2018 Repurchase Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury stock, acquired (in shares) | shares	286,761
Treasury stock, acquired (in USD per share) | $ / shares	$ 15.28
Performance Cash Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 5,600
Performance Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 14,700
Grant of stock units (in shares) | shares	1,220,201
Weighted-average grant date fair value (in USD per share) | $ / shares	$ 12.03
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash—short and long-term incentive plans	$ 1,260	$ 1,079
Incentive compensation expense	3,643	3,197
General and administrative expenses | Equity-based compensation—restricted common units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	996	954
General and administrative expenses | Equity-based compensation—restricted performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	738	633
General and administrative expenses | Common units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive compensation expense	$ 649	$ 531

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PREFERRED UNITS (Details) $ / shares in Units, $ in Thousands	Nov. 28, 2023	Nov. 28, 2017 USD ($) $ / shares shares	Mar. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Class of Stock [Line Items]
Redemption maximum		$ 100,000
Redemption price (in USD per share) | $ / shares		$ 20.39
Period of redemption restriction		90 days
Series B Cumulative Convertible Preferred Units
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%	7.00%
Preferred stock, dividend distribution terms, period of readjustment	2 years
Distribution rate	2.00%
Preferred unit conversion ratio		1
Minimum underlying value for conversion trigger		$ 10,000
Preferred units, outstanding value			$ 300,478	$ 299,137
Accrued distributions			$ 7,400	$ 6,000
Series B Cumulative Convertible Preferred Units | 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

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EARNINGS PER UNIT - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Earnings Per Share [Abstract]
NET INCOME (LOSS)	$ 63,927	$ 134,443
Distributions on Series B cumulative convertible preferred units	(7,367)	(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,560	129,193
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	56,560	129,193
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,560	129,193
NUMERATOR:
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	56,560	129,193
Effect of dilutive securities	0	5,250
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$ 56,560	$ 134,443
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic) (in shares)	210,654	209,941
Effect of dilutive securities (in shares)	0	14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities (in shares)	210,654	224,910
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.27	$ 0.62
Per common unit (diluted) (in dollars per share)	$ 0.27	$ 0.60

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EARNINGS PER UNIT - Potentially Dilutive Securities Excluded from the Computation of Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 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	0

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COMMON UNITS - Narrative (Details) - USD ($) $ in Millions	Nov. 28, 2023	Nov. 28, 2017	Mar. 31, 2024	Oct. 30, 2023	Oct. 29, 2023
2023 Unit Repurchase Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount				$ 150.0
2018 Unit Repurchase Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount					$ 75.0
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)			15.00%
Preferred units distribution rate	9.80%	7.00%

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COMMON UNITS - Per Share Distributions to Common and Subordinated Unitholders (Details) - Common units - $ / shares	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Class of Stock [Line Items]
Distributions paid per common unit (in dollars per share)	$ 0.4750	$ 0.4750
Distributions declared per common unit (in dollars per share)	$ 0.4750	$ 0.4750

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SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended		12 Months Ended
	Apr. 17, 2024	May 07, 2024	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Unproved Oil And Gas Properties
Subsequent Event [Line Items]
Total consideration					$ 14.6
Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)			$ 0.4750	$ 0.4750
Subsequent Event | Unproved Oil And Gas Properties
Subsequent Event [Line Items]
Total consideration		$ 12.3
Subsequent Event | Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)	$ 0.375