Black Stone Minerals - 10-Q quarterly report FY2026 Q2

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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, 2026


☐			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 July 31, 2026, there were 212,710,571 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Item 1. Condensed Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)


	June 30, 2026		December 31, 2025
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,674	$	1,478

Accrued revenue and accounts receivable	71,060		65,572
Commodity derivative assets, net	9,848		18,864

Prepaid expenses and other current assets	6,425		9,722
TOTAL CURRENT ASSETS	89,007		95,636
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,099,220 and $1,063,709 at June 30, 2026 and December 31, 2025, respectively	3,134,600		3,079,340
Accumulated depreciation, depletion, amortization and impairment	(1,874,181)		(1,855,332)
Oil and natural gas properties, net	1,260,419		1,224,008
Other property and equipment, net of accumulated depreciation of $16,229 and $15,768 at June 30, 2026 and December 31, 2025, respectively	1,020		1,126
NET PROPERTY AND EQUIPMENT	1,261,439		1,225,134
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	15,465		14,784
TOTAL ASSETS	$	1,365,911	$	1,335,554
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,133	$	2,823
Accrued liabilities	12,111		19,388
Commodity derivative liabilities, net	5,823		—
Other current liabilities	1,627		2,412
TOTAL CURRENT LIABILITIES	23,694		24,623
LONG–TERM LIABILITIES
Credit facility	196,000		154,000
Accrued incentive compensation	841		1,011
Commodity derivative liabilities, net	3,072		—
Asset retirement obligations	23,312		22,716
Other long-term liabilities	5,526		4,748
TOTAL LIABILITIES	252,445		207,098
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at June 30, 2026 and December 31, 2025, respectively	300,478		300,478
EQUITY
Partners' equity – general partner interest	—		—
Partners' equity – common units, 212,703 and 211,873 units outstanding at June 30, 2026 and December 31, 2025, respectively	812,988		827,978
TOTAL EQUITY	812,988		827,978
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,365,911	$	1,335,554

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,
	2026		2025		2026		2025
REVENUE
Oil and condensate sales	$	75,151	$	55,807	$	129,265	$	105,900
Natural gas and natural gas liquids sales	40,275		46,189		103,683		104,424
Lease bonus and other income	6,696		4,714		13,083		11,639
Revenue from contracts with customers	122,122		106,710		246,031		221,963
Gain (loss) on commodity derivative instruments, net	26,850		52,784		(37,700)		(3,217)
TOTAL REVENUE	148,972		159,494		208,331		218,746
OPERATING (INCOME) EXPENSE
Lease operating expense	2,098		2,990		3,991		5,152
Production costs and ad valorem taxes	6,108		9,026		15,308		19,211
Exploration expense	4,825		1,749		9,450		6,859
Depreciation, depletion, and amortization	9,402		9,187		19,187		18,317

General and administrative	16,076		13,924		32,908		29,096
Accretion of asset retirement obligations	393		337		782		669

TOTAL OPERATING EXPENSE	38,902		37,213		81,626		79,304
INCOME FROM OPERATIONS	110,070		122,281		126,705		139,442
OTHER INCOME (EXPENSE)
Interest and investment income	57		56		89		120
Interest expense	(3,816)		(2,270)		(7,177)		(3,667)
Other income (expense), net	47		(39)		13		81
TOTAL OTHER EXPENSE	(3,712)		(2,253)		(7,075)		(3,466)
NET INCOME	106,358		120,028		119,630		135,976

Distributions on Series B cumulative convertible preferred units	(7,366)		(7,367)		(14,732)		(14,733)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	98,992	$	112,661	$	104,898	$	121,243
ALLOCATION OF NET INCOME:
General partner interest	$	—	$	—	$	—	$	—
Common units	98,992		112,661		104,898		121,243
	$	98,992	$	112,661	$	104,898	$	121,243
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.47	$	0.53	$	0.49	$	0.57
Per common unit (diluted)	$	0.47	$	0.53	$	0.49	$	0.57
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	212,596		211,689		212,483		211,472
Weighted average common units outstanding (diluted)	212,596		226,761		212,483		211,472

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, 2025	211,873	$	827,978
Repurchases of common units	(162)	(2,335)


Restricted units granted, net of forfeitures	782	—
Equity–based compensation	—	5,688
Distributions to common unitholders ($0.30 per unit)	—	(63,700)
Charges to partners' equity for accrued distribution equivalent rights	—	(333)
Distributions on Series B cumulative convertible preferred units ($0.50 per unit)	—	(7,366)
Net income	—	13,272
BALANCE AT MARCH 31, 2026	212,493	$	773,204


Issuance of common units for acquisition of oil and natural gas properties	—	2,800
Restricted units granted, net of forfeitures	210	—
Equity–based compensation	—	1,988
Distributions to common unitholders ($0.30 per unit)	—	(63,750)
Charges to partners' equity for accrued distribution equivalent rights	—	(246)
Distributions on Series B cumulative convertible preferred units ($0.50 per unit)	—	(7,366)
Net income	—	106,358
BALANCE AT JUNE 30, 2026	212,703	$	812,988


	Common units	Partners' equity
BALANCE AT DECEMBER 31, 2024	210,695	$	828,961
Repurchases of common units	(221)	(3,289)

Issuance of common units for acquisition of oil and natural gas properties	256	3,905
Restricted units granted, net of forfeitures	900	—
Equity–based compensation	—	5,919
Distributions to common unitholders ($0.375 per unit)	—	(79,177)
Charges to partners' equity for accrued distribution equivalent rights	—	(414)
Distributions on Series B cumulative convertible preferred units ($0.50 per unit)	—	(7,366)
Net income	—	15,948
BALANCE AT MARCH 31, 2025	211,630	$	764,487
Repurchases of common units	(36)	(466)

Issuance of common units for acquisition of oil and natural gas properties	253	3,512
Restricted units granted, net of forfeitures	(5)	—
Equity–based compensation	—	1,691
Distributions to common unitholders ($0.375 per unit)	—	(79,363)
Charges to partners' equity for accrued distribution equivalent rights	—	(384)
Distributions on Series B cumulative convertible preferred units ($0.50 per unit)	—	(7,367)
Net income	—	120,028
BALANCE AT JUNE 30, 2025	211,842	$	802,138

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,
	2026		2025
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	119,630	$	135,976
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	19,187		18,317

Accretion of asset retirement obligations	782		669
Amortization of deferred charges	525		550
(Gain) loss on commodity derivative instruments, net	37,700		3,217
Net cash (paid) received on settlement of commodity derivative instruments	(21,012)		(465)
Equity-based compensation	6,031		5,015


Changes in operating assets and liabilities:
Accrued revenue and accounts receivable	(5,516)		(8,948)
Prepaid expenses and other current assets	3,296		(5,623)
Accounts payable, accrued liabilities, and other	(4,984)		(3,297)
Settlement of asset retirement obligations	(112)		(100)
NET CASH PROVIDED BY OPERATING ACTIVITIES	155,527		145,311
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(45,904)		(37,990)
Additions to oil and natural gas properties	(344)		(326)
Additions to oil and natural gas properties leasehold costs	(6,296)		(4,620)
Purchases of other property and equipment	(355)		(151)
Proceeds from the sale of oil and natural gas properties	121		400

NET CASH USED IN INVESTING ACTIVITIES	(52,778)		(42,687)
CASH FLOWS FROM FINANCING ACTIVITIES

Distributions to common unitholders	(127,450)		(158,540)
Distributions to Series B cumulative convertible preferred unitholders	(14,732)		(14,733)


Repurchases of common units	(2,335)		(3,289)
Borrowings under credit facility	179,000		179,000
Repayments under credit facility	(137,000)		(105,000)
Debt issuance costs and other	(36)		(62)
NET CASH USED IN FINANCING ACTIVITIES	(102,553)		(102,624)
NET CHANGE IN CASH AND CASH EQUIVALENTS	196		—
Cash and cash equivalents – beginning of the period	1,478		2,519
Cash and cash equivalents – end of the period	$	1,674	$	2,519
SUPPLEMENTAL DISCLOSURE
Interest paid	$	6,643	$	2,939
Common units issued for property acquisitions	$	2,800	$	7,417

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED 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 condensed 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, 2025 ("2025 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, 2026 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 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 reportable segment, which consists of a single operating segment. The Partnership generates revenue from the sale of oil and natural gas, as well as lease bonus and other income that is derived from its oil and natural gas properties. These properties are all located within the continental U.S., including all of the major onshore producing basins. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker ("CODM") in deciding how to allocate resources and assess performance. The Partnership’s co-chief executive officers, collectively, have been determined to be the CODM and allocate resources and assess performance based upon net income reported on the consolidated statements of operations. The significant segment expenses regularly provided to the CODM include lease operating expense, production costs and ad valorem taxes, exploration expense, depreciation, depletion, and amortization, general and administrative expense, and interest expense. Other segment items include accretion of asset retirement obligations, gain on sale of assets, net, interest and investment income, and other income (expense), net. These significant expenses and other segment items are the same as the line items presented in the consolidated statements of operations. The CODM is not regularly provided with additional expense information beyond what is presented in the consolidated statements of operations. The measure of segment assets is reported on the consolidated balance sheets as total assets. The CODM uses net income to evaluate the income generated from segment assets in deciding whether to reinvest profits into the Partnership's oil and natural gas properties or for other activities such as distributions to unitholders and reducing outstanding borrowings as applicable.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Significant accounting policies are disclosed in the Partnership’s 2025 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, 2026.

Accrued Revenue and Accounts Receivable

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


	June 30, 2026		December 31, 2025

	(in thousands)
Accrued revenue	$	64,443	$	62,679
Accounts receivable	6,617		2,893
Total accrued revenue and accounts receivable	$	71,060	$	65,572

Accrued Liabilities

Accrued liabilities consisted of the following:


	June 30, 2026		December 31, 2025
	(in thousands)
Accrued incentive compensation	$	5,749	$	7,824
Accrued property taxes	3,139		6,029
Accrued lease operating expenses	1,169		1,985
Accrued general and administrative	932		847
Accrued seismic costs	—		1,500
Accrued other	1,122		1,203
Total accrued liabilities	$	12,111	$	19,388

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures, which enhances the disclosures required for certain expense captions in the Partnership's annual and interim consolidated financial statements. The guidance is effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on its disclosures.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 - OIL AND NATURAL GAS PROPERTIES

Acquisitions

During the six months ended June 30, 2026, the Partnership acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $48.7 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $45.9 million in cash that was funded with borrowings under the Credit Facility and funds from operating activities, and $2.8 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, 2025, the Partnership acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $114.5 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $107.1 million in cash that was funded with borrowings under the Credit Facility and funds from operating activities, and $7.4 million in equity, that was funded through the issuance of common units of the Partnership based on the fair value of the common units issued on the acquisition dates.

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.

As of June 30, 2026, 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 statements of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of June 30, 2026 and December 31, 2025. 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, 2026, the Partnership had eight counterparties, all of which are lenders under the Credit Facility.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2026
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, net	$	16,843	$	(6,995)	$	9,848
Long-term asset	Deferred charges and other long-term assets	6,906		(1,554)		5,352
Total assets		$	23,749	$	(8,549)	$	15,200
Liabilities:
Current liability	Commodity derivative liabilities, net	$	12,818	$	(6,995)	$	5,823
Long-term liability	Commodity derivative liabilities, net	4,626		(1,554)		3,072
Total liabilities		$	17,444	$	(8,549)	$	8,895


		December 31, 2025
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, net	$	24,930	$	(6,066)	$	18,864
Long-term asset	Deferred charges and other long-term assets	4,325		(196)		4,129
Total assets		$	29,255	$	(6,262)	$	22,993
Liabilities:
Current liability	Commodity derivative liabilities, net	$	6,066	$	(6,066)	$	—
Long-term liability	Commodity derivative liabilities, net	196		(196)		—
Total liabilities		$	6,262	$	(6,262)	$	—

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities), as well as net cash paid or received on settlements, are presented on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments, net and consist of the following for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
Derivatives not designated as hedging instruments	2026		2025		2026		2025
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(29,313)	$	(65,999)	$	22,993	$	(13,609)
Gain (loss) on oil derivative instruments	12,519		17,224		(52,717)		16,411
Gain (loss) on natural gas derivative instruments	14,331		35,560		15,017		(19,628)
Net cash paid (received) on settlements of oil derivative instruments	19,352		(4,038)		16,061		(3,656)
Net cash paid (received) on settlements of natural gas derivative instruments	(10,584)		892		4,951		4,121
Net change in fair value of commodity derivative instruments	35,618		49,638		(16,688)		(2,752)
Ending fair value of commodity derivative instruments	$	6,305	$	(16,361)	$	6,305	$	(16,361)

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for oil as of June 30, 2026:


		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2026

Second Quarter	205,000	$	64.39	$	62.00	$	67.35
Third Quarter	615,000	64.39		62.00		67.35
Fourth Quarter	615,000	64.39		62.00		67.35
2027
First Quarter	450,000	$	62.83	$	58.13	$	76.28
Second Quarter	450,000	62.83		58.13		76.28
Third Quarter	450,000	62.83		58.13		76.28
Fourth Quarter	450,000	62.83		58.13		76.28

The Partnership entered into the following derivative contracts for oil subsequent to June 30, 2026:


		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2027
First Quarter	30,000	$	69.95	$	69.95	$	69.95
Second Quarter	30,000	69.95		69.95		69.95
Third Quarter	30,000	69.95		69.95		69.95
Fourth Quarter	30,000	69.95		69.95		69.95

The Partnership had the following open derivative contracts for natural gas as of June 30, 2026:


		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2026


Third Quarter	12,880,000	$	3.73	$	3.50	$	4.46
Fourth Quarter	12,880,000	3.73		3.50		4.46
2027
First Quarter	7,200,000	$	3.91	$	3.77	$	4.00
Second Quarter	7,280,000	3.91		3.77		4.00
Third Quarter	7,360,000	3.91		3.77		4.00
Fourth Quarter	7,360,000	3.91		3.77		4.00

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 - FAIR VALUE MEASUREMENTS

Fair value is defined as the amount at which an asset (or liability) could be sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of fair value hierarchy for the six months ended June 30, 2026 and 2025.

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, 2026 and December 31, 2025 approximated the fair value due to variable market rates of interest.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED 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, 2026
Financial Assets
Commodity derivative instruments	$	—	$	23,749	$	—	$	(8,549)	$	15,200
Financial Liabilities
Commodity derivative instruments	$	—	$	17,444	$	—	$	(8,549)	$	8,895
As of December 31, 2025
Financial Assets
Commodity derivative instruments	$	—	$	29,255	$	—	$	(6,262)	$	22,993
Financial Liabilities
Commodity derivative instruments	$	—	$	6,262	$	—	$	(6,262)	$	—

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values when impaired.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership had no business combinations for the six months ended June 30, 2026 or the year ended December 31, 2025. 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 impaired. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. This evaluation is performed on a depletable unit basis.

When assessing producing properties for impairment, the Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine future cash flows associated with those properties include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and, with respect to estimating fair value, a risk-adjusted discount rate. When assessing unproved properties for impairment, an impairment loss is recognized to the extent the carrying value within a depletable unit exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

The Partnership’s estimates of fair value are determined at discrete points in time based on relevant market data. These estimates involve uncertainty, and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs for the six months ended June 30, 2026 or the year ended December 31, 2025. There were no assets measured at fair value on a non-recurring basis for the six months ended June 30, 2026 or the year ended December 31, 2025.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED 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, 2030. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if the Partnership terminates its hedge positions or sells oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base. The borrowing base was reaffirmed in April 2025, October 2025 and April 2026 at $580.0 million. After each redetermination, the Partnership elected to maintain cash commitments under the Credit Facility at $375.0 million. The next semi-annual redetermination is scheduled for October 2026.

The Partnership’s borrowings under the Credit Facility bear interest at a floating rate determined by the type of loan the Partnership has elected to take: a SOFR loan or a base-rate loan. Both types of loans bear interest at a reference rate plus a margin that varies with the amount of borrowings outstanding under the Credit Facility. The reference rate for SOFR loans is equal to SOFR as published by the Federal Reserve Bank of New York, adjusted for the borrowing term, plus 2.50%, which is referred to as Adjusted Term SOFR. Effective October 31, 2025, Adjusted Term SOFR was amended to remove the additional 0.10% "adjustment" to the underlying SOFR reference rate. The reference rate for base rate loans is the highest of (a) Wells Fargo’s prime commercial lending rate for that day, (b) the Federal Funds Rate in effect on that day plus 0.50%, and (c) Adjusted Term SOFR for a one-month tenor, plus 1.00%. As of June 30, 2026 and December 31, 2025, the applicable margin for the base rate loans ranged from 1.50% to 2.50%, and the margin for SOFR loans ranged from 2.50% to 3.50%.

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

The weighted-average interest rate of the Credit Facility was 6.58% during the six months ended June 30, 2026 and 7.03% during the year ended December 31, 2025. 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 3.0:1.0. As of June 30, 2026, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $196.0 million and $154.0 million at June 30, 2026 and December 31, 2025, respectively. The unused portion of the available borrowings under the Credit Facility was $178.6 million and $221.0 million at June 30, 2026 and December 31, 2025, respectively.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be material to the 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, 2026 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 expenses in the consolidated statements of operations for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

	(in thousands)
Cash—short and long-term incentive plans	$	2,466	$	1,235	$	3,971	$	2,521
Equity-based compensation—restricted common units	1,257		1,172		2,316		2,135
Equity-based compensation—restricted performance units	640		238		2,541		1,780
Board of Directors incentive plan	583		550		1,174		1,100
Total incentive compensation expense	$	4,946	$	3,195	$	10,002	$	7,536

For the six months ended June 30, 2026, the Partnership repurchased 162,066 common units at a weighted average price of $14.41 per unit for the purpose of satisfying tax withholding obligations upon the vesting of certain long-term incentive equity awards held by the Partnership's 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.

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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Series B cumulative convertible preferred units are entitled to quarterly distributions based on an annual distribution rate (the “Distribution Rate”), which is subject to adjustment every two years (each, a “Readjustment Date”) with the last Readjustment Date on November 28, 2025. The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the Distribution Rate shall be increased by 2.0% per annum for such quarter. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date. The Partnership cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions. The Series B cumulative convertible preferred units have a stated liquidation preference of $21.41 per unit, or $315.0 million in the aggregate, plus any accrued and unpaid distributions, or if greater, the amount such units would be entitled to if converted into common units.

The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.39, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10 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 during biennial 90-day windows. On August 21, 2025, the Partnership entered into an agreement with the holders of its Series B cumulative convertible preferred units. Under the agreement, the Partnership agreed not to exercise its redemption option, and the holders agreed to vote their preferred units in accordance with the recommendations of the Partnership’s Board of Directors on ordinary course matters and to certain customary transfer and standstill restrictions. These provisions remain in effect through November 27, 2027, with the next redemption window opening on November 28, 2027.

The Partnership must provide 20 business days' notice to the holders of the Series B cumulative convertible preferred units of its intent to redeem, and the holders may either allow the redemption to occur or elect to convert the Series B cumulative convertible preferred units into common units as described above.

The Series B cumulative convertible preferred units had a carrying value of $300.5 million, including accrued distributions of $7.4 million, as of June 30, 2026 and December 31, 2025.

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 CONDENSED 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,
	2026		2025		2026		2025

	(in thousands, except per unit amounts)
NET INCOME	$	106,358	$	120,028	$	119,630	$	135,976

Distributions on Series B cumulative convertible preferred units	(7,366)		(7,367)		(14,732)		(14,733)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	98,992	$	112,661	$	104,898	$	121,243
ALLOCATION OF NET INCOME:
General partner interest	$	—	$	—	$	—	$	—
Common units	98,992		112,661		104,898		121,243
	$	98,992	$	112,661	$	104,898	$	121,243
NUMERATOR:
Numerator for basic EPU - net income attributable to common unitholders	$	98,992	$	112,661	$	104,898	$	121,243
Effect of dilutive securities	—		7,367		—		—
Numerator for diluted EPU - net income attributable to common unitholders after the effect of dilutive securities	$	98,992	$	120,028	$	104,898	$	121,243
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)	212,596		211,689		212,483		211,472
Effect of dilutive securities	—		15,072		—		—
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	212,596		226,761		212,483		211,472
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.47	$	0.53	$	0.49	$	0.57
Per common unit (diluted)	$	0.47	$	0.53	$	0.49	$	0.57

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,
	2026	2025	2026	2025

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner (the "Board"), holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control, may not vote on any matter.

The partnership agreement generally provides that 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 the Distribution Rate applied to the face amount of the preferred units per annum. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date.

• second, to the holders of common units.

Common Unit Repurchase Program

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program, terminating its existing $75.0 million program authorized in 2018. The unit repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the six months ended June 30, 2026. 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 22, 2026, the Board approved a distribution for the three months ended June 30, 2026 of $0.32 per common unit. Distributions will be payable on August 13, 2026 to unitholders of record at the close of business on August 6, 2026.

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 condensed 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, 2025 ("2025 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 and Haynesville 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;

•domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products and energy-related products;

•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 2025 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 ("U.S."). 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, 2026, our mineral and royalty interests were located in 41 states in the continental U.S., including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 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. 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

Development Activity

At the end of the second quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating two rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas successfully turned to sales 4 gross (0.4 net) wells in July 2026. Adamas’s development program remains on track with the development agreements, with a total of 14 wells spud in the previous program year that ended on June 30, 2026. Of these wells, 6 gross (0.6 net) have turned to sales as of July 31, 2026, and 8 gross (0.7 net) are expected to turn to sales during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.

Our agreement with Revenant Energy ("Revenant") covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres. Under the original agreement, Revenant was obligated to drill a minimum of 6 wells in 2026, increasing annually to a minimum of 25 wells per year by 2030. We also secured a non-operated working interest partner for the development. In November 2025, the agreement was amended to maintain the original 6-well commitment for 2026 and convert future commitments to completed gross lateral-foot targets at one well per 7,000 lateral feet, allowing longer

laterals while keeping overall development levels unchanged. In May 2026, we entered into an amendment to the JEA that reduced the Program Year 1 drilling commitments to 4 wells following the well control incident in April 2026 affecting one of the two wells spud in the first quarter of 2026. The amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program. Development activity continued during the second quarter of 2026, with Revenant spudding two additional wells.

In November 2025, we entered into a 220,000 gross acre development agreement with Caturus Energy, LLC ("Caturus"), which aims to push the Shelby Trough westward towards the Western Haynesville. Activity will begin with approximately 2 gross (0.2 net) wells in the second half of 2026 and ramp to approximately 12 gross (0.8 net) wells annually by 2031, supported by minimum annual lateral-foot requirements, all net to our interest. In addition to the 2 gross development wells in 2026, Caturus is currently drilling a pilot well in Cherokee County, consistent with the terms of the agreement.

In the Permian Basin, Blue Arrow Operating is in progress on a development of 25 gross (1.9 net) wells in the southern Delaware Basin. Three wells were turned to sales during the quarter with the remaining expected to come online in the second half of 2026 and first half of 2027.

For additional information about our Shelby Trough development agreements, please read "Liquidity and Capital Resources - Shelby Trough Development Agreements."

Acquisition Activity

In the second quarter of 2026, consistent with our previously announced acquisition strategy, we acquired $37.2 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through June 2026, we have completed $299.7 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.

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 during the first half of 2026 compared to the same period in 2025, primarily due to the conflict with Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices were lower during the first half of 2026 relative to the prior-year period. Natural gas prices were elevated early in 2026 due to winter weather and tighter inventories but generally moderated during the remainder of the first six months as production growth increased market supplies. Recent price strength at the end of the second quarter was driven by rising electric power demand and increased U.S. liquefied natural gas ("LNG") export volumes.

Given the dynamic nature of commodity markets, we cannot reasonably estimate how long price levels or 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:


	2026				2025
Benchmark Prices1	Second Quarter		First Quarter			Second Quarter		First Quarter
WTI spot oil ($/Bbl)	$	70.56	$	102.86		$	66.30	$	71.87
Henry Hub spot natural gas ($/MMBtu)	3.34		2.88			3.26		4.11

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:


	2026		2025
U.S. Rotary Rig Count1	Second Quarter	First Quarter	Second Quarter	First Quarter
Oil	440	409	432	484
Natural gas	125	127	109	103
Other	8	7	6	5
Total	573	543	547	592

1 Source: Baker Hughes Incorporated

Natural Gas Storage

The majority of the production volumes attributable to our interests are derived from natural gas production. 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 U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 Tcf at the end of October 2026, which would be 5% higher than the five-year average.

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


	2026		2025
Region1	Second Quarter	First Quarter	Second Quarter	First Quarter
East	587	270	602	284
Midwest	706	350	688	364
Mountain	230	208	228	165
Pacific	313	258	287	202
South Central	1,086	775	1,148	758
Total	2,922	1,861	2,953	1,773

1 Source: EIA

Natural Gas Exports

Net natural gas exports averaged 17.2 Bcf per day during the second quarter of 2026, a 14% increase from the 2025 average. The EIA forecasts average exports of 17.3 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that LNG exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.

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 natural gas liquids ("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 of our production is derived from properties located in the U.S.

•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. Although the growth in LNG export capacity and global shipping has increased connectivity among certain markets, transportation remains infrastructure-dependent and subject to capacity constraints, and prices may continue to vary by region.

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 fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. 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. 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, 2026 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.

The Credit Facility allows but does not require us 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, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027.

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, seismic data acquisition costs, non-cash equity-based compensation, unrealized gains and losses on commodity derivative instruments, 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.

Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three and six months ended June 30, 2025, for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation. Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests.

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 or liquidity presented in accordance with generally accepted accounting principles ("GAAP") in the U.S. 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) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

	(in thousands)
Net income	$	106,358	$	120,028	$	119,630	$	135,976
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	9,402		9,187		19,187		18,317

Interest expense	3,816		2,270		7,177		3,667
Income tax expense (benefit)	(2)		8		60		(77)
Accretion of asset retirement obligations	393		337		782		669
Seismic data acquisition costs	4,519		1,400		8,775		6,229
Equity–based compensation	2,480		1,960		6,031		5,015
Unrealized (gain) loss on commodity derivative instruments	(35,618)		(49,639)		16,688		2,751

Adjusted EBITDA	91,348		85,551		178,330		172,547
Adjustments to reconcile to Distributable Cash Flow:
Change in deferred revenue	—		(1)		(1)		(2)
Cash interest expense	(3,554)		(1,994)		(6,653)		(3,117)
Preferred unit distributions	(7,366)		(7,367)		(14,732)		(14,733)
Distributable Cash Flow	$	80,428	$	76,189	$	156,944	$	154,695

Results of Operations

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025

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


	Three Months Ended June 30,
	2026		2025		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	863		863		—		—	%
Natural gas (MMcf)1	13,133		13,710		(577)		(4.2)	%
Equivalents (MBoe)	3,052		3,148		(96)		(3.0)	%
Equivalents/day (MBoe)	33.5		34.6		(1.1)		(3.2)	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	87.08	$	64.67	$	22.41	34.7	%
Natural gas ($/Mcf)1	3.07		3.37		(0.30)		(8.9)	%
Equivalents ($/Boe)	$	37.82	$	32.40	$	5.42	16.7	%
Revenue:
Oil and condensate sales	$	75,151	$	55,807	$	19,344	34.7	%
Natural gas and natural gas liquids sales1	40,275		46,189		(5,914)		(12.8)	%
Lease bonus and other income	6,696		4,714		1,982		42.0	%
Revenue from contracts with customers	122,122		106,710		15,412		14.4	%
Gain (loss) on commodity derivative instruments, net	26,850		52,784		(25,934)		(49.1)	%
Total revenue	$	148,972	$	159,494	$	(10,522)	(6.6)	%
Operating expenses:
Lease operating expense	$	2,098	$	2,990	$	(892)	(29.8)	%
Production costs and ad valorem taxes	6,108		9,026		(2,918)		(32.3)	%
Exploration expense	4,825		1,749		3,076		175.9	%
Depreciation, depletion, and amortization	9,402		9,187		215		2.3	%

General and administrative	16,076		13,924		2,152		15.5	%
Other expense:
Interest expense	3,816		2,270		1,546		68.1	%

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, 2026 decreased compared to the quarter ended June 30, 2025. The decrease in total revenue in the second quarter of 2026 is primarily due to lower gains on our commodity derivative instruments and lower natural gas and NGL sales partially offset by increased oil and condensate sales as well as higher lease bonus and other income.

Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025 due to increased realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended June 30, 2026 and 2025.

Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended June 30, 2026 as compared to the corresponding prior period. The decrease between the comparative periods is due to lower realized commodity prices and slightly decreased production volumes. The decrease in production was driven by lower royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the quarters ended June 30, 2026 and 2025, 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 2026, gains from our commodity derivative instruments decreased compared to the same period in 2025. For the three months ended June 30, 2026, we recognized $8.8 million of realized losses and $35.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $3.2 million of realized gains and $49.6 million of unrealized gains in the same period in 2025. The unrealized gains on our commodity contracts during the second quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized gains for the same period in 2025 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 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play comprised the majority of lease bonus and other income for the second quarter of 2026, while the majority of lease bonus and other income in the second quarter of 2025 came from leasing activity in the Permian Basin and Bakken/Three Forks plays.

Operating and Other 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, 2026 as compared to the same period in 2025, 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, 2026, production costs and ad valorem taxes decreased compared to the quarter ended June 30, 2025. The decrease was primarily due to $4.2 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.

Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. For the quarter ended June 30, 2026, exploration expenses increased compared to the same period in 2025, primarily due to higher expenditures for seismic costs incurred in connection with ongoing seismic shoots tied to our development programs.

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, 2026 as compared to the same period in 2025 due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.

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, 2026, general and administrative expenses increased as compared to the

same period in 2025, primarily due to higher personnel costs, including $1.2 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Interest expense. Interest expense increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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



	Six Months Ended June 30,
	2026		2025		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	1,648		1,579		69		4.4	%
Natural gas (MMcf)1	28,399		28,563		(164)		(0.6)	%
Equivalents (MBoe)	6,381		6,340		41		0.6	%
Equivalents/day (MBoe)	35.3		35.0		0.3		0.9	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	78.44	$	67.07	$	11.37	17.0	%
Natural gas ($/Mcf)1	3.65		3.66		(0.01)		(0.3)	%
Equivalents ($/Boe)	$	36.51	$	33.17	$	3.34	10.1	%
Revenue:
Oil and condensate sales	$	129,265	$	105,900	$	23,365	22.1	%
Natural gas and natural gas liquids sales1	103,683		104,424		(741)		(0.7)	%
Lease bonus and other income	13,083		11,639		1,444		12.4	%
Revenue from contracts with customers	246,031		221,963		24,068		10.8	%
Gain (loss) on commodity derivative instruments, net	(37,700)		(3,217)		(34,483)		1,071.9	%
Total revenue	$	208,331	$	218,746	$	(10,415)	(4.8)	%
Operating expenses:
Lease operating expense	$	3,991	$	5,152	$	(1,161)	(22.5)	%
Production costs and ad valorem taxes	15,308		19,211		(3,903)		(20.3)	%
Exploration expense	9,450		6,859		2,591		37.8	%
Depreciation, depletion, and amortization	19,187		18,317		870		4.7	%

General and administrative	32,908		29,096		3,812		13.1	%
Other expense:
Interest expense	7,177		3,667		3,510		95.7	%

Revenue

Total revenue for the six months ended June 30, 2026 decreased slightly compared to the corresponding prior period. The decrease in total revenue is primarily due to increased losses on our commodity derivative instruments partially offset by increased oil and condensate sales as well as higher lease bonus and other income.

Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2026 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 higher mineral and royalty production in the Permian Basin and Bakken/Three Forks plays. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the six months ended June 30, 2026 and 2025.

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2026 were flat compared to the corresponding prior period. Both commodity prices and production volumes remained relatively consistent between the comparable periods. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the six months ended June 30, 2026 and 2025, respectively.

Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2026, we recognized an increased loss from our commodity derivative instruments compared to the corresponding period in 2025. In the six months ended June 30, 2026, we recognized $21.0 million of realized losses and $16.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $0.5 million of realized losses and $2.7 million of unrealized losses in the same period in 2025. Unrealized losses on our commodity contracts during the six months ended June 30, 2026 were driven by changes in forward oil price curves, compared to the corresponding period in 2025 when unrealized losses were driven by changes in forward natural gas price curves.

Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play and proceeds from the surface use waivers on our mineral acreage supporting solar development in Mississippi made up the majority of lease bonus and other income for the six months ended June 30, 2026, while a substantial portion of the activity in the corresponding period in 2025 came from leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana.

Operating and Other Expenses

Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to a reduction in nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. For the six months ended June 30, 2026, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2025, primarily due to $6.5 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.

Exploration expense. For the six months ended June 30, 2026, exploration expense increased as compared to the six months ended June 30, 2025. The increase was primarily driven by purchases of seismic data and costs from proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough area.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.

General and administrative. For the six months ended June 30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $2.3 million of cash compensation and $0.9 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Interest expense. Interest expense increased for the six months ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher 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. The Series B cumulative convertible preferred units are entitled to quarterly distributions based on an annual distribution rate (the "Distribution Rate"), which is subject to adjustment every two years (each, a "Readjustment Date") with the last Readjustment Date on November 28, 2025. The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the Distribution Rate shall be increased by 2.0% per annum for such quarter. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date. 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. On August 21, 2025, we entered into an agreement with the holders of the Series B cumulative convertible preferred units under which we agreed not to exercise our redemption option and the holders agreed to vote in accordance with Board recommendations and comply with customary transfer and standstill restrictions through November 27, 2027, with the next redemption window opening on November 28, 2027. Depending on market conditions among other factors, we may use funds from the future issuance of common units or other equity securities or debt to redeem some or all of the preferred units. 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 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. As of June 30, 2026, we had not made any repurchases under the program.

Cash Flows

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


	Six Months Ended June 30,
	2026		2025		Change

	(in thousands)
Cash flows provided by operating activities	$	155,527	$	145,311	$	10,216
Cash flows used in investing activities	(52,778)		(42,687)		(10,091)
Cash flows used in financing activities	(102,553)		(102,624)		71

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 increased for the six months ended June 30, 2026 as compared to the same period of 2025. The increase was primarily driven by higher oil sales due to increased realized oil prices and production volumes in the six months ended June 30, 2026. The overall increase was partially offset by higher cash paid for the settlement of commodity derivatives.

Investing Activities. Net cash used in investing activities in the six months ended June 30, 2026 increased as compared to the same period of 2025. The increase was primarily due to higher expenditures for acquisitions of oil and natural gas properties and leasehold costs in the six months ended June 30, 2026 compared to the same period of 2025.

Financing Activities. Net cash used in financing activities remained consistent for the six months ended June 30, 2026 as compared to the same period of 2025. The decreased distributions paid to common unitholders for the six months ended June 30, 2026, compared to the same period of 2025 was partially offset by higher repayments of our Credit Facility.

Development Capital Expenditures

Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.3 million during the six months ended June 30, 2026. We also spent $6.3 million to acquire leases in areas around our drilling programs during the six months ended June 30, 2026.

Acquisitions

During the six months ended June 30, 2026, we acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $48.7 million, including capitalized direct transaction costs. The consideration paid consisted of $45.9 million in cash that was funded with borrowings under our Credit Facility and funds from operating activities, and $2.8 million in equity, that was funded through the issuance of common units based on the fair value of the common units issued on the acquisition dates. Our 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.

Shelby Trough Development Agreements

We are party to a series of Joint Exploration Agreements ("JEAs"; each, a "JEA") with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage and reduced royalty rates in exchange for meeting minimum annual drilling commitments, as defined by either a minimum number of wells or minimum aggregate lateral feet drilled. Each JEA also includes a banking provision that allows operators that exceed their annual drilling commitments to carry forward excess drilling activity, measured by wells drilled or aggregate lateral feet, to satisfy future obligations, subject to defined caps. The agreements also allow operators to temporarily suspend drilling obligations if natural gas prices fall below certain thresholds. The duration of any such suspension period is subject to limitations specified in the agreements. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs.

For additional information about our development activities in the Shelby Trough, please read "Recent Developments."

Adamas Joint Exploration Agreements

We have two JEAs originally entered into with Aethon Energy and now operated by Adamas, covering a portion of our acreage in San Augustine County and Angelina County in East Texas. The agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas.

Adamas drilled a total of 14 wells during the program year that ended on June 30, 2026 and applied 2 of its 10 banked wells toward its commitment. As of July 31, 2026, 8 of those wells had not yet turned to sales and are expected to begin production during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.

Revenant Joint Exploration Agreement

In May 2025, we entered into a JEA with Revenant covering an expanded portion of our Shelby Trough acreage, primarily located in Angelina, Nacogdoches, and San Augustine counties in Texas. The agreement grants Revenant exclusive development rights across three designated areas of interest ("AOIs") and requires minimum annual drilling commitments that escalate over a five-year period, including test wells in certain areas, to maintain development rights across the full contract area. The agreement allows for non-operated working interest participation, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our retained undivided 35% working interest.

In November 2025, we entered into an amendment to the JEA that maintained the original 6-well commitment for Program Year 1, while revising the structure for subsequent years. After Program Year 1, well count commitments convert to completed gross lateral-foot commitments at a ratio of one well per 7,000 lateral feet, allowing Revenant to drill longer laterals while maintaining overall commitment levels.

In May 2026, we entered into an amendment to the JEA that reduced the Program Year 1 drilling commitments to 4 wells following the well control incident in April 2026 affecting one of the two wells spud in the first quarter of 2026. The amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program.

The table below summarizes the minimum gross lateral-foot drilling commitments under the amended agreement, following Program Year 1:


Revenant Drilling Commitments1
Program Year	Calendar Year	AOI 1	AOI 2	AOI 3	Total Gross Lateral Feet
2	2027	56,000	7,000	—	63,000
3	2028	70,000	—	—	70,000
4	2029	84,000	14,000	14,0002	112,000
5 and thereafter	2030 and beyond	105,000	35,000	21,000	161,000

1 Lateral-feet drilled in any AOI may be used to satisfy drilling commitments in other AOIs, except for the AOI 2 commitment in Program Year 2.

2 Revenant has the option to elect into the AOI 3 drilling commitment by June 30, 2028. If they do not make this election, the AOI 3 acreage and associated drilling commitment will be removed from the development program.

Caturus Joint Exploration Agreement

In November 2025, we entered into a JEA with Caturus covering an expanded portion of our Shelby Trough acreage, primarily in Angelina, Cherokee, Houston, and Nacogdoches counties in Texas. The agreement grants Caturus exclusive development rights across the contract area and requires minimum annual drilling commitments to maintain such rights. These commitments are measured in completed lateral feet on a net basis attributable to our mineral ownership interest and include pilot and test wells in the initial program years. The minimum net lateral-foot commitments escalate over a six-year period.

The table below summarizes the minimum net lateral-foot drilling commitments under the agreement:


Caturus Drilling Commitments
Program Year	Calendar Year	Net Lateral Feet
1	2026	6,000
2	2027	12,000
3	2028	12,600
4	2029	16,800
5	2030	21,000
6 and thereafter	2031 and beyond	25,200

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, 2030. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. We reaffirmed the borrowing base in April 2025, October 2025 and April 2026 at $580.0 million. After each redetermination, we elected to maintain cash commitments under the Credit Facility at $375.0 million. The next semi-annual redetermination is scheduled for October 2026.

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, 2026, 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.

Material Cash Requirements

As of June 30, 2026, there have been no material changes to our material cash requirements previously disclosed in our 2025 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of June 30, 2026, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2025 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 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 mitigate 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.

Based upon our open commodity derivative positions at June 30, 2026, a hypothetical $1 per barrel increase or decrease in the NYMEX WTI strip price would result in an increase or decrease of approximately $3.2 million in the fair value of our oil derivative contracts. Similarly, a hypothetical $0.10 per MMBtu increase or decrease in the NYMEX Henry Hub natural gas strip price would result in an increase or decrease of approximately $5.5 million in the fair value of our natural gas derivative contracts. These hypothetical changes in fair value could result in a gain or loss depending on whether commodity prices increase or decrease.

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, 2026. Applying this discount results in an approximate 1.2% reduction of proved reserve volumes as compared to the undiscounted June 30, 2026 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, 2026, we had eight counterparties, all of which were rated BBB or better by S&P Global Ratings 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, 2026, we had $190.3 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted average interest rate of 6.58%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $1.0 million for the six months ended June 30, 2026, 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, 2026 to provide reasonable assurance.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the quarter ended June 30, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition 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 2025 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 2025 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, 2026, we closed on purchases of certain mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers using, in part, an aggregate of 202,944 common units valued at $2.8 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

None.

Item 5. Other Information

During the three months ended June 30, 2026, 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)).

31.1*						Certification of Co-Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*						Certification of Co-Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3*						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 Co-Chief Executive Officers 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 4, 2026	By:	/s/ Fowler T. Carter
		Fowler T. Carter
		Co-Chief Executive Officer and President
		(Principal Executive Officer)

Date: August 4, 2026	By:	/s/ H. Taylor DeWalch
		H. Taylor DeWalch
		Co-Chief Executive Officer and President
		(Principal Executive Officer)

Date: August 4, 2026	By:	/s/ Chris R. Bonner
		Chris R. Bonner
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

Black Stone Minerals - 10-Q quarterly report FY2026 Q2

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		Page
PART I – FINANCIAL INFORMATION

Item 1.	Condensed 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	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 5.	Other Information	34
Item 6.	Exhibits	35

	Signatures	36