SEC Filing - Black Stone Minerals L.P.

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bsm-20240630

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 June 30, 2024


☐			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 August 2, 2024, there were 210,689,203 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	30
Item 4.	Controls and Procedures	31

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 5.	Other Information	32
Item 6.	Exhibits	33

	Signatures	34

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)


	June 30, 2024		December 31, 2023
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	26,669	$	70,282
Accounts receivable	73,825		82,253
Commodity derivative assets	10,967		38,273

Prepaid expenses and other current assets	3,057		2,319
TOTAL CURRENT ASSETS	114,518		193,127
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $929,291 and $890,338 at June 30, 2024 and December 31, 2023, respectively	3,078,212		3,026,394
Accumulated depreciation, depletion, amortization, and impairment	(1,983,801)		(1,961,899)
Oil and natural gas properties, net	1,094,411		1,064,495
Other property and equipment, net of accumulated depreciation of $14,349 and $14,163 at June 30, 2024 and December 31, 2023, respectively	876		1,007
NET PROPERTY AND EQUIPMENT	1,095,287		1,065,502
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,091		8,255
TOTAL ASSETS	$	1,216,896	$	1,266,884
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	5,632	$	6,270
Accrued liabilities	10,600		17,003
Commodity derivative liabilities	9,414		1,229
Other current liabilities	1,416		1,334
TOTAL CURRENT LIABILITIES	27,062		25,836
LONG–TERM LIABILITIES

Accrued incentive compensation	911		1,699
Commodity derivative liabilities	6,671		81
Asset retirement obligations	19,291		19,030
Other long-term liabilities	2,496		2,893
TOTAL LIABILITIES	56,431		49,539
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at June 30, 2024 and December 31, 2023	300,478		299,137
EQUITY
Partners' equity – general partner interest	—		—
Partners' equity – common units, 210,682 and 209,991 units outstanding at June 30, 2024 and December 31, 2023, respectively	859,987		918,208
TOTAL EQUITY	859,987		918,208
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,216,896	$	1,266,884

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
REVENUE
Oil and condensate sales	$	73,889	$	61,551	$	145,113	$	122,460
Natural gas and natural gas liquids sales	36,493		41,619		78,504		99,042
Lease bonus and other income	4,789		2,527		8,337		6,502
Revenue from contracts with customers	115,171		105,697		231,954		228,004
Gain (loss) on commodity derivative instruments	(5,547)		11,303		(16,837)		63,574
TOTAL REVENUE	109,624		117,000		215,117		291,578
OPERATING (INCOME) EXPENSE
Lease operating expense	2,579		2,866		5,011		5,534
Production costs and ad valorem taxes	13,469		12,844		26,507		25,511
Exploration expense	14		4		17		8
Depreciation, depletion, and amortization	11,356		10,421		22,995		21,568

General and administrative	13,395		11,854		27,485		24,502
Accretion of asset retirement obligations	321		250		638		495

TOTAL OPERATING EXPENSE	41,134		38,239		82,653		77,618
INCOME (LOSS) FROM OPERATIONS	68,490		78,761		132,464		213,960
OTHER INCOME (EXPENSE)
Interest and investment income	462		373		1,132		530
Interest expense	(626)		(645)		(1,255)		(1,459)
Other income (expense)	(4)		(97)		(92)		(196)
TOTAL OTHER EXPENSE	(168)		(369)		(215)		(1,125)
NET INCOME (LOSS)	68,322		78,392		132,249		212,835

Distributions on Series B cumulative convertible preferred units	(7,366)		(5,250)		(14,733)		(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	60,956	$	73,142	$	117,516	$	202,335
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—	$	—
Common units	60,956		73,142		117,516		202,335
	$	60,956	$	73,142	$	117,516	$	202,335
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.29	$	0.35	$	0.56	$	0.96
Per common unit (diluted)	$	0.29	$	0.35	$	0.56	$	0.95
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	210,703		209,967		210,679		209,954
Weighted average common units outstanding (diluted)	210,703		209,967		210,679		224,923

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

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
Repurchases of common units	(4)	(68)

Issuance of common units for property acquisitions	64	1,039
Restricted units granted, net of forfeitures	(34)	—
Equity–based compensation	—	1,935
Distributions	—	(79,014)
Charges to partners' equity for accrued distribution equivalent rights	—	(185)
Distributions on Series B cumulative convertible preferred units	—	(7,366)
Net income (loss)	—	68,322
BALANCE AT JUNE 30, 2024	210,682	$	859,987


	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



Restricted units granted, net of forfeitures	5	—
Equity–based compensation	—	2,076
Distributions	—	(99,734)
Charges to partners' equity for accrued distribution equivalent rights	—	(471)
Distributions on Series B cumulative convertible preferred units	—	(5,250)
Net income (loss)	—	78,392
BALANCE AT JUNE 30, 2023	209,968	$	914,880

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended June 30,
	2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	132,249	$	212,835
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	22,995		21,568

Accretion of asset retirement obligations	638		495
Amortization of deferred charges	536		513
(Gain) loss on commodity derivative instruments	16,837		(63,574)
Net cash (paid) received on settlement of commodity derivative instruments	25,616		41,469
Equity-based compensation	4,588		4,635


Changes in operating assets and liabilities:
Accounts receivable	8,481		63,477
Prepaid expenses and other current assets	(737)		(715)
Accounts payable, accrued liabilities, and other	(5,990)		(10,083)
Settlement of asset retirement obligations	(368)		(195)
NET CASH PROVIDED BY OPERATING ACTIVITIES	204,845		270,425
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(49,478)		—
Additions to oil and natural gas properties	(388)		(2,503)
Additions to oil and natural gas properties leasehold costs	(1,839)		(9)
Purchases of other property and equipment	(55)		(121)
Proceeds from the sale of oil and natural gas properties	79		—

NET CASH USED IN INVESTING ACTIVITIES	(51,681)		(2,633)
CASH FLOWS FROM FINANCING ACTIVITIES

Distributions to common unitholders	(178,913)		(199,334)
Distributions to Series B cumulative convertible preferred unitholders	(13,393)		(10,500)


Repurchases of common units	(4,449)		(5,496)
Borrowings under credit facility	9,000		64,000
Repayments under credit facility	(9,000)		(74,000)
Debt issuance costs and other	(22)		(103)
NET CASH USED IN FINANCING ACTIVITIES	(196,777)		(225,433)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(43,613)		42,359
CASH AND CASH EQUIVALENTS – beginning of the period	70,282		4,307
CASH AND CASH EQUIVALENTS – end of the period	$	26,669	$	46,666
SUPPLEMENTAL DISCLOSURE
Interest paid	$	719	$	975

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

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 six months ended June 30, 2024 are not necessarily indicative of the results to be expected for the full year.

In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.

The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income (loss) and equity in the accompanying unaudited interim consolidated financial statements.

The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

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 six months ended June 30, 2024.

Accounts Receivable

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


	June 30, 2024		December 31, 2023

	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	68,993	$	77,560
Other	4,832		4,693
Total accounts receivable	$	73,825	$	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 six months ended June 30, 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.

During the six months ended June 30, 2024, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in the Gulf Coast land region from various sellers for an aggregate of $50.5 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $49.5 million in cash that was funded from operating activities and $1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

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

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

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 County 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 June 30, 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	%

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Angelina County 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 June 30, 2024, 45 wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

Aethon Time-Out

Under our Joint Exploration Agreements ("JEAs") with Aethon in San Augustine and Angelina counties in East Texas, 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 when natural gas prices fall below certain thresholds. When the "time-out" provision is invoked, the current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months. In December 2023, the Partnership received notice that Aethon was exercising the time-out provisions under the JEAs in San Augustine and Angelina counties, implying a maximum resumption date in September 2024. Aethon drilled three wells in the first quarter of 2024 in San Augustine county despite the invocation of the time-out and has brought 16 total wells online in the first half of 2024.

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 six months ended June 30, 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2024, the Partnership’s open derivative contracts consisted of fixed-price swap contracts. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of June 30, 2024 and December 31, 2023. See "Note 5 - Fair Value Measurements" for additional information.

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of June 30, 2024, the Partnership had seven counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under the Credit Facility.

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date:


		June 30, 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	$	16,391	$	(5,424)	$	10,967
Long-term asset	Deferred charges and other long-term assets	34		(34)		—
Total assets		$	16,425	$	(5,458)	$	10,967
Liabilities:
Current liability	Commodity derivative liabilities	$	14,838	$	(5,424)	$	9,414
Long-term liability	Commodity derivative liabilities	6,705		(34)		6,671
Total liabilities		$	21,543	$	(5,458)	$	16,085


		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

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 June 30,				Six Months Ended June 30,
Derivatives not designated as hedging instruments	2024		2023		2024		2023
	(in thousands)
Beginning fair value of commodity derivative instruments	$	12,248	$	67,927	$	37,335	$	28,941
Gain (loss) on oil derivative instruments	(1,226)		7,360		(24,456)		14,782
Gain (loss) on natural gas derivative instruments	(4,321)		3,943		7,619		48,792
Net cash paid (received) on settlements of oil derivative instruments	5,526		(3,172)		5,405		(1,772)
Net cash paid (received) on settlements of natural gas derivative instruments	(17,345)		(25,012)		(31,021)		(39,697)
Net change in fair value of commodity derivative instruments	(17,366)		(16,881)		(42,453)		22,105
Ending fair value of commodity derivative instruments	$	(5,118)	$	51,046	$	(5,118)	$	51,046

The Partnership had the following open derivative contracts for oil as of June 30, 2024:


		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2024

Second Quarter	190,000	$	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 June 30, 2024:


		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2024


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	9,000,000	$	3.42	$	3.34	$	3.65
Second Quarter	9,100,000	3.42		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

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 six months ended June 30, 2024 and 2023.

The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of June 30, 2024 and December 31, 2023 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See "Note 4 - Commodity Derivative Financial Instruments" for additional information.

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 June 30, 2024
Financial Assets
Commodity derivative instruments	$	—	$	16,425	$	—	$	(5,458)	$	10,967
Financial Liabilities
Commodity derivative instruments	$	—	$	21,543	$	—	$	(5,458)	$	16,085
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 six months ended June 30, 2024 or the year ended December 31, 2023. See "Note 3 - Oil and Natural Gas Properties".

Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

The Partnership’s estimates of fair value are determined at discrete points in time based on relevant market data. These estimates involve uncertainty, and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of June 30, 2024 or December 31, 2023. There were no assets measured at fair value on a non-recurring basis for the six months ended June 30, 2024 or the year ended December 31, 2023.

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 June 30, 2024, the applicable margin for the base rate loans ranged from 1.50% to 2.50%, and the margin for SOFR loans ranged from 2.50% to 3.50%.

The Partnership is obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary SOFR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date.

The weighted-average interest rate of the Credit Facility was 7.96% during the six months ended June 30, 2024 and 7.36% for the twelve months ended December 31, 2023. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. Distributions are not permitted if there is a default under the Credit Facility (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0. As of June 30, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.

There was no aggregate principal balance outstanding at June 30, 2024 and December 31, 2023. The unused portion of the available borrowings under the Credit Facility was $375.0 million at June 30, 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.

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 June 30, 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 June 30,				Six Months Ended June 30,
	2024		2023		2024		2023

	(in thousands)
Cash—short and long-term incentive plans	$	1,125	$	854	$	2,385	$	1,933
Equity-based compensation—restricted common units	965		942		1,961		1,896
Equity-based compensation—restricted performance units	691		1,053		1,429		1,686
Board of Directors incentive plan	549		522		1,198		1,053
Total incentive compensation expense	$	3,330	$	3,371	$	6,973	$	6,568

For the six months ended June 30, 2024, the Partnership repurchased 291,163 common units at a weighted average price of $15.28 per unit for the purpose of satisfying tax withholding obligations upon the vesting of certain long-term incentive equity awards held by our executive officers and certain other employees. Specifically, when an employee's equity award vests, the Partnership withholds a portion of the units to cover the employee's tax liability.

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 $13.5 million for the performance equity awards (1,110,496 performance units with a weighted-average grant date fair value of $12.13 per unit). As of June 30, 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

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 June 30, 2024 and a carrying value of $299.1 million, including accrued distributions of $6.0 million, as of December 31, 2023. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

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.

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 June 30,				Six Months Ended June 30,
	2024		2023		2024		2023

	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	68,322	$	78,392	$	132,249	$	212,835

Distributions on Series B cumulative convertible preferred units	(7,366)		(5,250)		(14,733)		(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	60,956	$	73,142	$	117,516	$	202,335
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—	$	—
Common units	60,956		73,142		117,516		202,335
	$	60,956	$	73,142	$	117,516	$	202,335
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders	$	60,956	$	73,142	$	117,516	$	202,335
Effect of dilutive securities	—		—		—		10,500
Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities	$	60,956	$	73,142	$	117,516	$	212,835
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)	210,703		209,967		210,679		209,954
Effect of dilutive securities	—		—		—		14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	210,703		209,967		210,679		224,923
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.29	$	0.35	$	0.56	$	0.96
Per common unit (diluted)	$	0.29	$	0.35	$	0.56	$	0.95

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 June 30,		Six Months Ended June 30,
	2024	2023	2024	2023

	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	15,072	14,969	15,072	—

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.

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 June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Distributions declared and paid per common unit	$	0.3750	$	0.4750	$	0.8500	$	0.9500

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 six months ended June 30, 2024. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.

NOTE 12 - SUBSEQUENT EVENTS

Distribution

On July 24, 2024, the Board approved a distribution for the three months ended June 30, 2024 of $0.375 per common unit. Distributions will be payable on August 16, 2024 to unitholders of record at the close of business on August 9, 2024.

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;

•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 June 30, 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. In the first half of 2024, revenues from Aethon's operations in the Shelby Trough made up 6% of our total revenues. 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.

Under the JEAs, 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 when natural gas prices fall below specified thresholds. When the "time-out" provision is invoked, the current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months. In December 2023, we received notice that Aethon was exercising the time-out provisions under the JEAs in San Augustine and Angelina, implying a maximum resumption date in September 2024. Aethon drilled three wells in the first quarter of 2024 in San Augustine county despite the invocation of the time-out and has brought 16 total wells online in the first half of 2024. During the second quarter, we continued working with Aethon to firm up future development plans in light of Aethon's previously announced invocation of a time-out.

Austin Chalk Update

We remain focused on full field development, which includes working with multiple operators on drilling and field optimization opportunities in the Brookeland Field to enhance production and increase reserves from the Austin Chalk formation.

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.

Oil prices increased from the prior period ended June 30, 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 increased during the second quarter of 2024 because of less natural gas-directed drilling and production curtailments due to low natural gas prices in the first quarter of 2024 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	Second Quarter		First Quarter			Second Quarter		First Quarter
WTI spot oil price ($/Bbl)	$	82.83	$	83.96		$	70.66	$	75.68
Henry Hub spot natural gas ($/MMBtu)	2.42		1.54			2.48		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	Second Quarter	First Quarter	Second Quarter	First Quarter
Oil	479	506	545	592
Natural gas	97	112	124	160
Other	5	3	5	3
Total	581	621	674	755

1 Source: Baker Hughes Incorporated

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 4.0 Tcf at the end of October 2024, which would be 6% 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	Second Quarter	First Quarter	Second Quarter	First Quarter
East	660	363	643	335
Midwest	779	510	705	421
Mountain	239	162	173	80
Pacific	282	227	216	73
South Central	1,174	996	1,141	921
Total	3,134	2,258	2,878	1,830

1 Source: EIA

Natural Gas Exports

Net natural gas exports averaged 11.9 Bcf per day during the first half of 2024, consistent with the average for the full year of 2023. The EIA expects U.S. LNG exports will increase as LNG export projects come on line in late 2024 and mid-2025. The EIA forecasts average exports of 12.5 Bcf per day for the remainder of 2024 and 14.3 Bcf per day for 2025.

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.

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 June 30, 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 swaps and collars 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 June 30, 2024, we had hedged 72% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively. As of June 30, 2024, we had also hedged 69% and 66% 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.

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 June 30,				Six Months Ended June 30,
	2024		2023		2024		2023

	(in thousands)
Net income (loss)	$	68,322	$	78,392	$	132,249	$	212,835
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	11,356		10,421		22,995		21,568

Interest expense	626		645		1,255		1,459
Income tax expense (benefit)	51		139		186		286
Accretion of asset retirement obligations	321		250		638		495
Equity–based compensation	2,205		2,517		4,588		4,635
Unrealized (gain) loss on commodity derivative instruments	17,366		16,881		42,453		(22,105)

Adjusted EBITDA	100,247		109,245		204,364		219,173
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue	(1)		(2)		(2)		(7)
Cash interest expense	(358)		(387)		(719)		(946)
Preferred unit distributions	(7,366)		(5,250)		(14,733)		(10,500)
Distributable cash flow	$	92,522	$	103,606	$	188,910	$	207,720

Results of Operations

Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023

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


	Three Months Ended June 30,
	2024		2023		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	953		846		107		12.6	%
Natural gas (MMcf)1	16,350		14,670		1,680		11.5	%
Equivalents (MBoe)	3,678		3,291		387		11.8	%
Equivalents/day (MBoe)	40.4		36.2		4.2		11.6	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	77.53	$	72.76	$	4.77	6.6	%
Natural gas ($/Mcf)1	2.23		2.84		(0.61)		(21.5)	%
Equivalents ($/Boe)	$	30.01	$	31.35	$	(1.34)	(4.3)	%
Revenue:
Oil and condensate sales	$	73,889	$	61,551	$	12,338	20.0	%
Natural gas and natural gas liquids sales1	36,493		41,619		(5,126)		(12.3)	%
Lease bonus and other income	4,789		2,527		2,262		89.5	%
Revenue from contracts with customers	115,171		105,697		9,474		9.0	%
Gain (loss) on commodity derivative instruments	(5,547)		11,303		(16,850)		(149.1)	%
Total revenue	$	109,624	$	117,000	$	(7,376)	(6.3)	%
Operating expenses:
Lease operating expense	$	2,579	$	2,866	$	(287)	(10.0)	%
Production costs and ad valorem taxes	13,469		12,844		625		4.9	%
Exploration expense	14		4		10		250.0	%
Depreciation, depletion, and amortization	11,356		10,421		935		9.0	%

General and administrative	13,395		11,854		1,541		13.0	%
Other expense:
Interest expense	626		645		(19)		(2.9)	%

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 June 30, 2024 decreased compared to the quarter ended June 30, 2023. The decrease in total revenue in the second 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 were partially offset by an increase in oil and condensate sales.

Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2024 as compared to the corresponding period in 2023 primarily due to higher production volumes and realized commodity prices. 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 95% and 93% of total oil and condensate volumes for quarters ended June 30, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended June 30, 2024 as compared to the corresponding prior period. The decrease was due to lower realized commodity prices between the comparative periods partially offset by an increase in production volumes. The increase in production volumes was driven by an increase in royalty interest production volumes, primarily within the Haynesville/Bossier play, including 29 new wells coming online from the Aethon development program in the Shelby Trough subsequent to the second quarter of 2023. Mineral and royalty interest production accounted for 94% and 93% of our natural gas volumes for the quarters ended June 30, 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 second 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 June 30, 2024, we recognized $11.8 million of realized gains and $17.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $28.2 million of realized gains and $16.9 million of unrealized losses in the same period in 2023. The unrealized losses on our commodity contracts during the second quarters of 2024 and 2023 were primarily 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 second quarter of 2024 was higher than the same period in 2023. Leasing activity in the Permian Basin made up the majority of lease bonus and other income for the second quarter of 2024, while the majority of the second quarter 2023 activity came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

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 June 30, 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 June 30, 2024, production costs and ad valorem taxes increased as compared to the quarter ended June 30, 2023, primarily due to higher production taxes stemming from increased production volumes.

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 June 30, 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 June 30, 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 June 30, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to an increase in cash compensation driven by an increase in salaries as well as a separation payment related to the departure of a senior executive.

Interest expense. Interest expense in the second quarter of 2024 was consistent with the corresponding period in 2023 with minimal average outstanding borrowings under our Credit Facility during each period. Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs.

Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023

The following table shows our production, revenues, pricing, and expenses for the periods presented:



	Six Months Ended June 30,
	2024		2023		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	1,876		1,639		237		14.5	%
Natural gas (MMcf)1	32,820		31,121		1,699		5.5	%
Equivalents (MBoe)	7,346		6,826		520		7.6	%
Equivalents/day (MBoe)	40.4		37.7		2.7		7.2	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	77.35	$	74.72	$	2.63	3.5	%
Natural gas ($/Mcf)1	2.39		3.18		(0.79)		(24.8)	%
Equivalents ($/Boe)	$	30.44	$	32.45	$	(2.01)	(6.2)	%
Revenue:
Oil and condensate sales	$	145,113	$	122,460	$	22,653	18.5	%
Natural gas and natural gas liquids sales1	78,504		99,042		(20,538)		(20.7)	%
Lease bonus and other income	8,337		6,502		1,835		28.2	%
Revenue from contracts with customers	231,954		228,004		3,950		1.7	%
Gain (loss) on commodity derivative instruments	(16,837)		63,574		(80,411)		(126.5)	%
Total revenue	$	215,117	$	291,578	$	(76,461)	(26.2)	%
Operating expenses:
Lease operating expense	$	5,011	$	5,534	$	(523)	(9.5)	%
Production costs and ad valorem taxes	26,507		25,511		996		3.9	%
Exploration expense	17		8		9		112.5	%
Depreciation, depletion, and amortization	22,995		21,568		1,427		6.6	%

General and administrative	27,485		24,502		2,983		12.2	%
Other expense:
Interest expense	1,255		1,459		(204)		(14.0)	%

Revenue

Total revenue for the six months ended June 30, 2024 decreased compared to the corresponding prior period. The decrease in total revenue 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 were partially offset by an increase in oil and condensate sales.

Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2024 increased compared to the corresponding prior period primarily due to higher production volumes and realized commodity prices. The increase in oil and condensate production was driven by mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for the six months ended June 30, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2024 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes. The increase in production volumes was driven by an increase in royalty interest production volumes, primarily within the Haynesville/Bossier play, including 29 new wells coming online from the Aethon development program in the Shelby Trough subsequent to the second quarter of 2023. Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the six months ended June 30, 2024 and 2023, respectively.

Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2024, we recognized a loss from our commodity derivative instruments compared to a gain for the same period in 2023. In the six months ended June 30, 2024, we recognized $25.6 million of realized gains and $42.5 million of unrealized losses from our oil and natural gas commodity contracts, compared to $41.5 million of realized gains and $22.1 million of unrealized gains in the same period in 2023. The unrealized losses on our commodity contracts during the six months ended June 30, 2024 and the unrealized gains in the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2024 was higher than the same period in 2023. Leasing activity in the Permian Basin and the Austin Chalk play trend and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas composed the majority of lease bonus and other income for the six months ended June 30, 2024, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

Operating and Other Expenses

Lease operating expense. Lease operating expense decreased for the six months ended June 30, 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. For the six months ended June 30, 2024, production costs and ad valorem taxes increased as compared to the six months ended June 30, 2023, primarily due to an increase in production taxes from higher oil commodity prices and production volumes.

Exploration expense. Exploration expense was minimal for the six months ended June 30, 2024 and for the six months ended June 30, 2023.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the six months ended June 30, 2024 as compared to the same period in 2023, primarily due to increased production volumes.

General and administrative. For the six months ended June 30, 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 cash compensation. The increase in cash compensation was driven by increases in salaries and costs recognized under our short-term cash incentive plan.

Interest expense. Interest expense was lower in the six months ended June 30, 2024 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

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:


	Six Months Ended June 30,
	2024		2023		Change

	(in thousands)
Cash flows provided by operating activities	$	204,845	$	270,425	$	(65,580)
Cash flows provided by (used in) investing activities	(51,681)		(2,633)		(49,048)
Cash flows provided by (used in) financing activities	(196,777)		(225,433)		28,656

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 six months ended June 30, 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 partially offset by higher oil sales. The overall decrease was also due to a reduction in cash received on the settlement of commodity derivatives in the six months ended June 30, 2024 compared to the same period of 2023.

Investing Activities. Net cash used in investing activities in the six months ended June 30, 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 six months ended June 30, 2024 as compared to no acquisition activity in the corresponding prior period.

Financing Activities. Cash flows used in financing activities decreased for the six months ended June 30, 2024 as compared to the same period of 2023. The decrease was primarily due to lower distributions paid to unitholders and no net repayments on our Credit Facility for the six months ended June 30, 2024 compared to net repayments for the six months ended June 30, 2023.

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 $0.4 million has been invested in the six months ended June 30, 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 June 30, 2024, we have also spent $1.8 million acquiring leases in areas around our drilling programs.

Acquisitions

During the six months ended June 30, 2024, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $50.5 million, including capitalized direct transaction costs. The consideration paid consisted of $49.5 million in cash that was funded from operating activities and $1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. These acquisitions were considered asset acquisitions and were primarily located in the Gulf Coast land region. 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 June 30, 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 June 30, 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 June 30, 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 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 June 30, 2024. Applying this discount results in an approximate 2.5% reduction of proved reserve volumes as compared to the undiscounted June 30, 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 June 30, 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 six months ended June 30, 2024, we had $0.2 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted average interest rate of 7.96%. 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 six months ended June 30, 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 June 30, 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 June 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

During the three months ended June 30, 2024, we closed on purchases of certain mineral and royalty interests using an aggregate of 63,776 common units valued at $1.0 million to fund the purchases.

The issuance of the common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.

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 June 30, 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

June 1 - June 30, 2024

4,402

15.51

—

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 June 30, 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.

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^

Separation Agreement and General Release of Claims, dated as of June 14, 2024, by and among Evan Kiefer, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on June 18, 2024 (SEC File No. 001- 37362)).

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.

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: August 6, 2024	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		President, Chief Executive Officer, and Chairman
		(Principal Executive Officer)

Date: August 6, 2024	By:	/s/ Taylor DeWalch
		Taylor DeWalch
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

Document

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: August 6, 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.

Document

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, Taylor DeWalch, 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: August 6, 2024						/s/ Taylor DeWalch
						Taylor DeWalch
						Chief Financial Officer
						Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

Document

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 Taylor DeWalch, 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: August 6, 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: August 6, 2024						/s/ Taylor DeWalch
						Taylor DeWalch Chief Financial Officer Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.