What changed in this filing

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Item 9A. Controls and Procedures

2026-02-24 compared with 2025-02-25 · 316 added, 305 removed, 886 unchanged (41% of the section changed)

11 unchanged sentences

Based on this evaluation, our general partner’s management believes that our internal control over financial reporting was effective as of December 31, 2025.

This Annual Report includes an attestation report of Ernst & Young LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2024, which is included in the Annual Report on page F-2.

This Annual Report includes an attestation report of Deloitte & Touche LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2025, which is included in the Annual Report on page F-5.

Changes in Internal Control over Financial Reporting

There were no changes in our system of 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 December 31, 2024, that have materially affected, or are reasonably likely to materially affect, our 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 December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

OTHER INFORMATION

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

Except as described below, during the three months ended December 31, 2025, 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.

On December 4, 2025 , Steve Putman , our Senior Vice President, General Counsel, and Secretary , adopted a trading arrangement for the sale of common units (a “Rule 10b5-1 Trading arrangement”) that is intended to satisfy the affirmative defense conditions of Securities Exchange Act Rule 10b5-1(c).

Putman’s Rule 10b5-1 Trading Plan provides for the sale of approximately 90,000 common units, subject to adjustment upon future settlement of certain outstanding unit-based awards and associated distribution equivalent rights, pursuant to the terms of the plan and will terminate on the earlier of (i) December 4, 2026 , (ii) the first date on which all trades set forth in the plan have been executed or (iii) such date as the plan is otherwise terminated according to its terms .

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

5 unchanged sentences

Name Age Position With The General Partner

73 Chairman, Chief Executive Officer, and President

Taylor DeWalch 35 Senior Vice President, Chief Financial Officer and Treasurer

74 Executive Chairman of the Board of Directors

Carter 46 Co-Chief Executive Officer and President

Taylor DeWalch 36 Co-Chief Executive Officer and President

Bonner 36 Senior Vice President, Chief Financial Officer, and Treasurer

Steve Putman 50 Senior Vice President, General Counsel, and Secretary

Clark 48 Senior Vice President, Chief Commercial Officer

Carter 45 Senior Vice President, Corporate Development

Bonner 35 Vice President and Chief Accounting Officer

Barth 63 Director

Mark DeWalch 64 Director

Hamman 65 Director

Linn 74 Director

Longmaid 48 Director

Mathis 58 Director

Randall 59 Director

1 unchanged sentence

Whitehead 50 Director

We have a Code of Business Conduct and Ethics that applies to our directors, officers, and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, and the other senior financial officers, each as required by SEC and NYSE rules.

We have a Code of Business Conduct and Ethics that applies to our directors, officers, and employees as well as a Financial Code of Ethics that applies to our Co-Chief Executive Officers, Chief Financial Officer, Principal Accounting Officer, and the other senior financial officers, each as required by SEC and NYSE rules.

Each of the foregoing is available on our website at www.blackstoneminerals.com in the “Corporate Governance” section.

1 unchanged sentence

Investor Relations.

We intend to disclose amendments to and waivers from our Financial Code of Ethics, if any, on our website, www.blackstoneminerals.com , promptly following the date of any such amendment or waiver.

We intend to disclose amendments to and waivers, if any, from our Code of Business Conduct and Ethics and Financial Code of Ethics, as required, on our website, www.blackstoneminerals.com , promptly following the date of any such amendment or waiver.

EXECUTIVE COMPENSATION

5 unchanged sentences

PRINCIPAL ACCOUNTING FEES AND SERVICES

Our independent registered public accounting firm is Ernst & Young LLP, Houston TX, Auditor Firm ID:

Our independent registered public accounting firm is Deloitte & Touche LLP, Houston TX, Auditor Firm ID:

Information required by this item is incorporated by reference to the 2026 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2025.

27 unchanged sentences

and Minerals 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 December 12, 2017 (SEC File No.

(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.

Black Stone Minerals, L.P.

1 unchanged sentence

(incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No.

Black Stone Minerals, L.P.

2025 Long-Term Incentive Plan, dated as of April 16, 2025, by Black Stone Minerals GP, L.L.C.

(incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on June 18, 2025 (SEC File No.

Fifth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A.

and PNC Capital Markets LLC, as Co-Syndication Agents, Zions Bancorporation, N.A., DBA Amegy Bank, as Documentation Agent, and the lenders signatory thereto, dated as of October 31, 2022 (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.'s Quarterly Report on Form 10-Q filed on November 1, 2022 (SEC File No.

Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No.

333-202875)).

Form of Non-Employee Director Unit Grant Notice and Award Agreement under the Black Stone Minerals, L.P.

2025 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Quarterly Report on Form 10-Q filed on November 4, 2025 (SEC File No.

Form of Severance Agreement for Thomas L.

8 unchanged sentences

2025 Long-Term Incentive Plan.

LTI Form of LTI Award Grant Notice and Award Agreement (Performance Cash Award) under the Black Stone Minerals, L.P.

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.'s Quarterly Report on Form 10-Q filed on May 3, 2022 (SEC File No.

10.1 0 ^

LTI Form of LTI Award Grant Notice and Award Agreement (Performance Equity Award) under the Black Stone Minerals, L.P.

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 of Black Stone Minerals, L.P.'s Quarterly Report on Form 10-Q filed on May 3, 2022 (SEC File No.

10.1 1 ^

(incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Quarterly Report on Form 10-Q filed on November 4, 2025 (SEC File No.

2024 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Restricted Units) under the Black Stone Minerals, L.P.

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Quarterly Report on Form 10-Q filed on May 7, 2024 (SEC File No.

10.1 2 ^

2024 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Performance Units) under the Black Stone Minerals, L.P.

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.'s Quarterly Report on Form 10-Q filed on May 7, 2024 (SEC File No.

2025 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Restricted Units) under the Black Stone Minerals, L.P.

2025 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.5 to Black Stone Minerals, L.P.’s Quarterly Report on Form 10-Q filed on November 4, 2025 (SEC File No.

2025 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Performance Units) under the Black Stone Minerals, L.P.

2025 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s Quarterly Report on Form 10-Q filed on November 4, 2025 (SEC File No.

10.14 ^*

Separation Agreement and General Release of Claims, dated as of June 14, 2024, by and among Evan Kiefer, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C.

(incorporated by reference to Exhibit 10.1 to Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on June 18, 2024 (SEC File No.

2026 Form of LTI Award Grant Notice and LTI Award Agreement (Leadership Performance Units) under the Black Stone Minerals, L.P.

2025 Long-Term Incentive Plan.

Separation Agreement and General Release of Claims, dated as of June 29, 2025, by and among Carrie Clark, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C.

(incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on June 30, 2025 (SEC File No.

Series B Preferred Unit Purchase Agreement, dated as of November 22, 2017, by and between Black Stone Minerals L.P.

and Mineral Royalties One, L.L.C.

(incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No.

(incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No.

Unitholder Agreement, dated as of August 22, 2025, by and between Black Stone Minerals, L.P.

and AP Basileia SPV, LLC.

(incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.

Current Report on Form 8-K filed on August 22, 2025 (SEC File No.

First Amendment to Fifth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, dated as of October 31, 2025 (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.'s Quarterly Report on Form 10-Q filed on November 4, 2025 (SEC File No.

Black Stone Minerals, L.P.

Insider Trading Policy.

Insider Trading Policy (incorporated herein by reference to Exhibit 19.1 to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 25, 2025 (SEC File No.

List of Subsidiaries of Black Stone Minerals, L.P.

Consent of Deloitte & Touche LLP

Consent of Ernst & Young LLP

Consent of Netherland, Sewell & Associates, Inc.

Certification of Chief Executive Officer of Black Stone Minerals, L.P.

Certification of Co-Chief Executive Officer of Black Stone Minerals, L.P.

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification of Co-Chief Executive Officer of Black Stone Minerals, L.P.

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification of Chief Financial Officer of Black Stone Minerals, L.P.

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P.

Certification of Co-Chief Executive Officers and Chief Financial Officer of Black Stone Minerals, L.P.

pursuant to 18 U.S.C.

17 unchanged sentences

February 24, 2026

/s/ Thomas L.

Chief Executive Officer and Chairman

/s/ Fowler T.

Co-Chief Executive Officer and President

February 24, 2026

Taylor DeWalch

Co-Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/ Fowler T.

Carter Co-Chief Executive Officer and President February 24, 2026

Carter (Principal Executive Officer)

Taylor DeWalch Co-Chief Executive Officer and President February 24, 2026

Taylor DeWalch (Principal Executive Officer)

Bonner Senior Vice President, Chief Financial Officer, and Treasurer February 24, 2026

Bonner (Principal Financial Officer)

Phillips Controller February 24, 2026

Phillips (Principal Accounting Officer)

/s/ Thomas L.

President, Chief Executive Officer and Chairman February 25, 2025

(Principal Executive Officer)

Taylor DeWalch Senior Vice President, Chief Financial Officer and Treasurer February 25, 2025

Taylor DeWalch (Principal Financial Officer)

Bonner Vice President and Chief Accounting Officer February 25, 2025

Bonner (Principal Accounting Officer)

Executive Chairman February 24, 2026

Barth Director February 24, 2026

Mark DeWalch Director February 24, 2026

Hamman Director February 24, 2026

Director February 24, 2026

2 unchanged sentences

Longmaid Director February 24, 2026

/s/ William N.

Mathis Director February 25, 2025

/s/ William E.

6 unchanged sentences

Report of Independent Registered Public Accounting Firm (PCAOB ID:

Report of Independent Registered Public Accounting Firm (PCAOB ID :

Consolidated Balance Sheets

4 unchanged sentences

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Black Stone Minerals GP, L.L.C.

and the unitholders of Black Stone Minerals, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Black Stone Minerals, L.P.

and subsidiaries (the "Partnership") as of December 31, 2025, the related consolidated statements of operations, equity, and cash flows, for the year ended December 31, 2025, and the related notes (collectively referred to as the "financial statements").

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2025, and the results of its operations and its cash flows for the year ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2026, expressed an unqualified opinion on the Partnership's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management.

Our responsibility is to express an opinion on the Partnership's financial statements based on our audits.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S.

federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.

Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Proved Oil and Gas Properties and Depletion – Estimated Proved Reserves —Refer to Note 2 to the Financial Statements

Critical Audit Matter Description

The Partnership’s capitalized costs of proved oil and gas properties are depleted using the units of production method based on estimated proved reserves.

In order to develop the Partnership’s estimated proved reserve volumes, consisting of crude oil and natural gas quantities, management and an independent petroleum engineering firm engaged by the Partnership use significant estimates and assumptions.

Changes in these estimates and assumptions could materially affect the estimated quantities of the Partnership’s reserves and therefore calculation of depletion expense.

Given the significant estimates and assumptions made by management and the independent petroleum engineering firm, performing audit procedures to evaluate the Partnership’s estimated proved reserve quantities required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s significant judgments and assumptions related to proved reserve quantities included the following, among others:

• We tested the design, implementation, and operating effectiveness of controls related to the Partnership’s estimation of proved reserves.

• We evaluated the Partnership’s estimated proved reserves by:

– Comparing the Partnership’s estimated future production from reserves to historical production volumes.

– Assessing the reasonableness of the production volume decline curve estimates by comparing to historical decline curves.

– Assessing the pricing and differential inputs used to estimate proved reserves.

– Reviewing internal communications to management and the Board of Directors.

– Reviewing the forecasts of future production in relation to information included in the Partnership’s press releases, investor presentations and relevant internal data.

• We evaluated the experience, qualifications and objectivity of management’s expert, an independent petroleum engineering firm, including the methodologies used to independently engineer proved reserve quantities.

/s/ Deloitte & Touche LLP

Houston, Texas

February 24, 2026

We have served as the Partnership’s auditor since 2025.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the Board of Directors of Black Stone Minerals, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Black Stone Minerals, L.P.

and subsidiaries (the Partnership) as of December 31, 2024 and 2023, the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S.

We have audited the accompanying consolidated balance sheet of Black Stone Minerals, L.P.

and subsidiaries (the Partnership) as of December 31, 2024, the related consolidated statements of operations, equity and cash flows for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with U.S.

generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 25, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

9 unchanged sentences

We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that:

(1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates .

Depreciation, Depletion and Amortization (“DD&A”) of Oil and Natural Gas Properties

Description of

At December 31, 2024, the net book value of the Partnership’s oil and natural gas properties was $1,132 million, and depreciation, depletion and amortization (“DD&A”) expense related to the Partnership’s oil and natural gas properties was $45 million for the year then ended.

As discussed in Note 2, the Partnership follows the successful efforts method of accounting for its oil and natural gas properties.

DD&A of oil and natural gas properties is recorded based on the units-of-production method.

Capitalized development costs are amortized on the basis of proved developed reserves, as determined by independent petroleum engineers.

Leasehold acquisition costs and costs to acquire proved properties are amortized on the basis of total proved reserves, also determined by independent petroleum engineers.

Proved oil and natural gas reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Judgment is required by the independent petroleum engineers in interpreting the data used to estimate proved oil and natural gas reserves.

Estimating proved oil and natural gas reserves also requires a selection and evaluation of inputs, including historical production.

Because of the complexity involved in estimating proved oil and natural gas reserves, management used independent petroleum engineers to determine the proved oil and natural gas reserves estimates as of December 31, 2024.

Auditing the Partnership’s oil and natural gas properties DD&A calculation is especially complex because of the use of the work of the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in determining proved oil and natural gas reserves.

How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls that address the risks of material misstatement relating to the oil and natural gas properties DD&A calculation, including management’s controls over the accuracy of the financial data used by the independent petroleum engineers for use in determining proved oil and natural gas reserves.

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the independent petroleum engineers used to determine the proved oil and natural gas reserves estimates.

In addition, in assessing whether we can use the work of the independent petroleum engineers we evaluated the accuracy of the financial data and inputs described above used by the engineers in determining proved oil and natural gas reserves by assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence.

Finally, we tested that the DD&A calculations are based on the appropriate proved oil and natural gas reserve balances from the independent petroleum engineers' reserve report.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2016.

We served as the Partnership’s auditor from 2016 to 2024.

Houston, Texas

1 unchanged sentence

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the Board of Directors of Black Stone Minerals, L.P.

To the Board of Directors of Black Stone Minerals GP, L.L.C.

and the unitholders of Black Stone Minerals, L.P.

Opinion on Internal Control Over Financial Reporting

We have audited Black Stone Minerals, L.P.

and subsidiaries’ internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).

In our opinion, Black Stone Minerals, L.P.

and subsidiaries (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2024 and 2023, the related consolidated statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 25, 2025, expressed an unqualified opinion thereon.

We have audited the internal control over financial reporting of Black Stone Minerals, L.P.

and subsidiaries (the "Partnership") as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Partnership and our report dated February 24, 2026, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting.

Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S.

5 unchanged sentences

Definition and Limitations of Internal Control Over Financial Reporting

A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A partnership’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership;

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership;

and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company;

and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

/s/ Deloitte & Touche LLP

Houston, Texas

7 unchanged sentences

Cash and cash equivalents $ 1,478 $ 2,519

Accounts receivable 71,093 82,253

Commodity derivative assets 1,824 38,273

Accrued revenue and accounts receivable 65,572 71,093

Commodity derivative assets, net 18,864 1,824

Prepaid expenses and other current assets 9,722 3,108

13 unchanged sentences

Accrued liabilities 19,388 17,242

Commodity derivative liabilities 3,852 1,229

Commodity derivative liabilities, net — 3,852

Other current liabilities 2,412 3,383

3 unchanged sentences

Accrued incentive compensation 1,011 1,234

Commodity derivative liabilities 11,581 81

Commodity derivative liabilities, net — 11,581

Asset retirement obligations 22,716 19,286

21 unchanged sentences

Revenue from contracts with customers 422,328 439,429 501,099

Gain (loss) on commodity derivative instruments ( 5,730 ) 91,117 ( 120,680 )

Gain (loss) on commodity derivative instruments, net 47,591 ( 5,730 ) 91,117

TOTAL REVENUE 469,919 433,699 592,216

6 unchanged sentences

Accretion of asset retirement obligations 1,374 1,298 1,042

(Gain) loss on sale of assets, net — ( 73 ) ( 17 )

Gain on sale of assets, net — — ( 73 )

TOTAL OPERATING EXPENSE 161,523 160,593 168,620

INCOME (LOSS) FROM OPERATIONS 273,106 423,596 482,498

INCOME FROM OPERATIONS 308,396 273,106 423,596

OTHER INCOME (EXPENSE)

1 unchanged sentence

Interest expense ( 8,930 ) ( 3,109 ) ( 2,754 )

Other income (expense) ( 337 ) ( 160 ) 215

Other income (expense), net 229 ( 337 ) ( 160 )

TOTAL OTHER EXPENSE ( 8,464 ) ( 1,780 ) ( 1,047 )

NET INCOME (LOSS) 271,326 422,549 476,480

NET INCOME 299,932 271,326 422,549

Distributions on Series B cumulative convertible preferred units ( 29,466 ) ( 29,466 ) ( 21,776 )

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 241,860 $ 400,773 $ 455,480

ALLOCATION OF NET INCOME (LOSS):

NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 270,466 $ 241,860 $ 400,773

ALLOCATION OF NET INCOME:

General partner interest $ — $ — $ —

1 unchanged sentence

$ 270,466 $ 241,860 $ 400,773

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:

NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:

Per common unit (basic) $ 1.28 $ 1.15 $ 1.91

11 unchanged sentences

Repurchases of common units ( 358 ) ( 5,496 )

Issuance of common units for property acquisitions — —

Restricted units granted, net of forfeitures 942 —

Equity-based compensation — 12,525

Distributions — ( 322,403 )

Distributions to common unitholders ($ 1.90 per unit)

— ( 398,824 )

Charges to partners' equity for accrued distribution equivalent rights — ( 2,221 )

Distributions on Series B cumulative convertible preferred units — ( 21,000 )

Net income (loss) — 476,480

Distributions on Series B cumulative convertible preferred units ($ 1.48 per unit)

Net income — 422,549

BALANCE AT DECEMBER 31, 2023 209,991 918,208

Repurchases of common units ( 291 ) ( 4,449 )

Issuance of common units for acquisition of oil and natural gas properties 64 1,039

Restricted units granted, net of forfeitures 931 —

Equity-based compensation — 10,441

Distributions — ( 398,824 )

Distributions to common unitholders ($ 1.60 per unit)

— ( 336,931 )

Charges to partners' equity for accrued distribution equivalent rights — ( 1,207 )

Distributions on Series B cumulative convertible preferred units — ( 21,776 )

Net income (loss) — 422,549

Distributions on Series B cumulative convertible preferred units ($ 2.00 per unit)

Net income — 271,326

BALANCE AT DECEMBER 31, 2024 210,695 828,961

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Equity-based compensation — 11,540

Distributions — ( 336,931 )

Distributions to common unitholders ($ 1.35 per unit)

— ( 285,654 )

Charges to partners' equity for accrued distribution equivalent rights — ( 975 )

Distributions on Series B cumulative convertible preferred units — ( 29,466 )

Net income (loss) — 271,326

Distributions on Series B cumulative convertible preferred units ($ 2.00 per unit)

Net income — 299,932

BALANCE AT DECEMBER 31, 2025 211,873 $ 827,978

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CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss) $ 271,326 $ 422,549 $ 476,480

Net income $ 299,932 $ 271,326 $ 422,549

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

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Equity-based compensation 9,620 8,564 10,829

(Gain) loss on sale of assets, net — ( 73 ) ( 17 )

Gain on sale of assets, net — — ( 73 )

Changes in operating assets and liabilities:

Accounts receivable 11,244 53,053 ( 39,513 )

Accrued revenue and accounts receivable 5,545 11,244 53,053

Prepaid expenses and other current assets ( 6,614 ) ( 789 ) ( 414 )

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Proceeds from the sale of oil and natural gas properties 834 2,795 73

Proceeds from farmouts of oil and natural gas properties — — 11,331

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES ( 112,236 ) ( 19,740 ) ( 1,215 )

NET CASH USED IN INVESTING ACTIVITIES ( 118,274 ) ( 112,236 ) ( 19,740 )

CASH FLOWS FROM FINANCING ACTIVITIES

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Interest paid $ 7,383 $ 1,961 $ 1,736

Common units issued for property acquisitions $ 7,417 $ 1,039 $ —

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

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All intercompany balances and transactions have been eliminated.

The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment.

Investments in which the Partnership has less than a 20 % ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable.

Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.

The consolidated financial statements include undivided interests in oil and natural gas property rights.

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Segment Reporting

The Partnership operates in a single reportable segment.

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 our oil and natural gas properties.

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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 chief executive officer has been determined to be the CODM and allocates resources and assesses performance based upon net income reported on the consolidated statements of operations.

The Partnership’s co-chief executive officers, collectively, have been determined to be the CODM and allocates resources and assesses 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, depletion, depreciation, 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.

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Actual results could differ from those estimates.

The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas.

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The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions.

A significant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired.

A significant decline in oil or natural gas prices could cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired.

As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.

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The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable

The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers.

Accounts receivable are recorded at the contractual amounts and do not bear interest.

Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accrued Revenue and Accounts Receivable

The Partnership’s accrued revenue and accounts receivable balance results primarily from operators’ sales of oil and natural gas to purchasers.

Accrued revenue and accounts receivable are recorded at the contractual amounts and do not bear interest.

Any concentration of operators may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.

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

(in thousands)

Accrued revenue $ 62,679 $ 67,047

Accounts receivable 2,893 4,046

Revenues from contracts with customers $ 67,047 $ 77,560

Other 4,046 4,693

Total accounts receivable $ 71,093 $ 82,253

Total accrued revenue and accounts receivable $ 65,572 $ 71,093

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 given price risk associated with its operations, the Partnership uses commodity derivative financial instruments.

To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and 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.

The Partnership does not enter into derivative instruments for speculative purposes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative instruments are recognized at fair value.

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therefore, gains and losses arising from changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments.

Realized and unrealized gains on commodity derivative instruments are recorded within cash flows from operating activities in the accompanying consolidated statements of cash flows.

Concentration of Credit Risk

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The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments.

The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances.

See "Note 7 – Significant Customers" for additional information.

The Partnership believes the credit quality of its operator base is high and has not experienced significant write-offs in its accounts receivable balances.

See "Note 7 – Significant Operators" for additional information.

Commodity derivative financial instruments may expose the Partnership to credit risk;

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See "Note 5 – Commodity Derivative Financial Instruments" for additional information.

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Oil and Natural Gas Properties

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The basis for grouping is a reasonable aggregation of properties with a common geographic location, which the Partnership also refers to as a depletable unit.

As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A.

As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, capitalized costs attributed to the proved properties are charged as an operating expense through DD&A.

DD&A of producing oil and natural gas properties is recorded based on the units-of-production method.

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DD&A expense related to the Partnership’s producing oil and natural gas properties was $ 35.7 million, $ 44.8 million, and $ 45.0 million for the years ended December 31, 2025, 2024, and 2023, respectively.

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The Partnership evaluates impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

See "Note 6 - Fair Value Measurements" for additional information.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss.

Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded.

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Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.

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Accrued Liabilities

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Accrued liabilities:

Accrued capital expenditures $ — $ 5

Accrued incentive compensation $ 7,824 $ 8,356

Accrued general and administrative 847 954

Accrued property taxes 6,029 6,498

Accrued lease operating expenses 1,985 713

Accrued seismic costs 1,500 —

Accrued other 1,203 721

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Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement.

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Lease expense for lease payments is recognized on a straight-line basis over the lease term.

The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

basis over the lease term.

In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

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As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product.

The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets.

The expected sales volumes and prices for these properties are estimated and recorded within the Accrued revenue and accounts receivable line item in the accompanying consolidated balance sheets.

The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.

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A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received.

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As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease bonus and other income

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Fair Value of Financial Instruments

The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, accounts payable, and accrued liabilities approximate their fair value at December 31, 2024 and 2023 due to the short-term maturity of these instruments.

The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, and accounts payable approximate their fair value at December 31, 2025 and 2024 due to the short-term maturity of these instruments.

See "Note 6 – Fair Value Measurements" for additional information.

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See "Note 9 – Incentive Compensation" for additional information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures ( Topic 280 ), which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses that are regularly provided to the CODM and included within reported measures of segment profit and loss.

In addition, the amendments provide new segment disclosure requirements for entities with a single reportable segment.

We adopted ASU 2023-07 on December 31, 2024.

The CODM evaluates significant expenses based off the consolidated financial statements and does not further disaggregate expenses in deciding how to allocate resources and assess performance.

Since the Partnership operates as a single reporting segment, all required segment reporting disclosures can be found in the consolidated financial statements.

The effect of the adoption had no impact on our consolidated financial statements.

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 Company's annual and interim consolidated financial statements.

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.

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The asset retirement obligation ("ARO") liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working interest oil and natural gas properties.

The current portion of our ARO is included in the line item Other current liabilities on the consolidated balance sheet, while the noncurrent portion is separately presented as Asset retirement obligations within long-term liabilities.

The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations.

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To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table describes changes to the Partnership’s ARO liability for the periods presented:

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Current asset retirement obligations $ 1,549 $ 2,032

Non-current asset retirement obligations $ 19,286 $ 19,030

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Noncurrent asset retirement obligations $ 22,716 $ 19,286

NOTE 4 — OIL AND NATURAL GAS PROPERTIES

During the year ended December 31, 2024, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in the Gulf Coast land region from various sellers for an aggregate of $ 110.4 million, including capitalized direct transaction costs, and were considered asset acquisitions.

During the year ended December 31, 2025, the Partnership acquired mineral and royalty interests that consisted of primarily 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 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 values of the common units issued on the acquisition dates.

During the year ended December 31, 2024, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $ 110.4 million, including capitalized direct transaction costs, and were considered asset acquisitions.

The cash portion of the consideration paid of $ 109.4 million was funded with our borrowings under our Credit Facility and funds from operating activities, and $ 1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

During the year ended December 31, 2023, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for cash consideration of $ 14.6 million, including capitalized direct transaction costs.

The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region.

The Partnership had no material acquisition activity during 2022.

The acquisitions were funded with cash from operating activities and were primarily located in East Texas.

Asset Exchange

In the third quarter of 2024, the Partnership closed on a transaction with a third-party operator whereby the Partnership received an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

The acreage surrendered in Mississippi constituted a partial disposition of unproved property and no gain or loss was recognized on the transaction.

Shelby Trough Development Agreements

In 2020 and 2021, BSM entered into Joint Exploration Agreements ("JEAs") with Aethon Energy ("Aethon") to develop certain portions of the Partnership's undeveloped acreage in San Augustine County and Angelina County in East Texas.

The agreements provide for minimum annual well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract areas.

The Partnership's development agreement and related drilling commitments covering its San Augustine County acreage are independent of the development agreement and associated commitments covering Angelina County.

Under the JEAs, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period when natural gas prices fall below certain thresholds.

In December 2023, the Partnership received notice that Aethon was exercising the time-out provisions under the JEAs in San Augustine and Angelina counties.

In September 2024, the Partnership entered into letter agreements with Aethon to amend the JEAs in San Augustine and Angelina counties.

In those agreements, the parties agreed to revise the current program year drill schedules under each JEA, to extend the respective program years by nine months, and to withdraw the invocation of the time-out provisions.

Aethon also released its rights under 25,000 acres from the parties' area of mutual interest defined in the original JEAs.

Farmout Agreements

The Partnership has entered into farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lowering its capital spending other than for mineral and royalty interest acquisitions.

Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests.

The Partnership's farmout arrangements cover its share of working interests under active development by Aethon in San Augustine County and Angelina County in East Texas.

The Partnership completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.

These transactions, which are described below, involved partial dispositions of unproved property, and no gains or losses were recognized.

In March 2025, the Partnership closed on a transaction with a third-party operator whereby the Partnership acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.

In February 2025, the Partnership closed on a transaction with a third-party operator whereby the Partnership exchanged oil and natural gas leases covering certain acreage in East Texas.

The Partnership acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

San Augustine County Farmout

In May 2021, the Partnership entered into a farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul").

In April 2022, the Partnership amended the Canaan Farmout and entered into a farmout agreement (the "JWM Farmout") with JWM Oil & Gas LLC ("JWM").

These agreements continue for a 10 year period, unless earlier terminated in accordance with the terms of the agreements.

The JWM Farmout terminated in September 2024 and the Canaan Farmout terminated in December 2024.

The Partnership does not intend to step into the working interests associated with the terminated agreements.

Unless the Partnership agrees otherwise with Aethon, the Partnership believes that Aethon, as operator and the party who has proposed the existing wells, has absorbed and will continue to absorb any non-consented interests.

The following tables present the working interests each farmout partner will earn within the contract area under the San

Augustine farmout agreements:

Brent Miller Area

Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis

Former Canaan Interest 64.0 % 32.0 %

Azul 20.0 % 10.0 %

Former JWM Interest 16.0 % 8.0 %

Total 100.0 % 50.0 %

Farmout Partner % of Partnership's Working Interest Maximum % on an 8/8th basis

Former Canaan Interest 40.0 % 10.0 %

Azul 50.0 % 12.5 %

Former JWM Interest 10.0 % 2.5 %

Total 100.0 % 25.0 %

Angelina County Farmout

In November 2020, the Partnership entered into a farmout agreement (the "Pivotal Farmout") with Pivotal.

The Pivotal Farmout continues until April 2028, unless earlier terminated in accordance to the terms of the agreement.

Pivotal earns 100 % of the Partnership's working interest (ranging from approximately 12.5 % to 25 % on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement.

In July 2024, the Partnership closed on a transaction with a third-party operator whereby the Partnership acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

Farmout Agreements

The Partnership previously entered into farmout arrangements covering all its non-operated working interests under its Joint Exploration Agreements ("JEAs";

each, a "JEA") with Aethon in San Augustine and Angelina Counties.

In May 2025, the farmout agreements covering the interests under the JEAs with Aethon terminated, and Aethon assumed the associated working interests as part of an amendment to the Partnership's JEAs with Aethon.

In June 2025, the Partnership entered into a farmout arrangement covering all its non-operated working interests under its JEA with Revenant Energy in Angelina, Nacogdoches, and San Augustine Counties, under which the Partnership farmed out its undivided 35 % working interest to an external capital provider.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties.

When assessing producing properties for impairment, the Partnership compared the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability.

When assessing producing properties for impairment, if a triggering event has been identified, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability.

When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

For the years ended December 31, 2024, 2023, and 2022, the Partnership did not identify any indicators or impairment and as such, no impairment of oil and natural gas properties were recognized.

For the years ended December 31, 2025, 2024, and 2023, the Partnership did not identify any indicators of impairment and as such, no impairment of oil and natural gas properties were recognized.

See "Note 6 - Fair Value Measurements" for additional information.

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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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

financial instruments.

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.

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The Partnership has not designated any of its contracts as fair value or cash flow hedges.

Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operations in the period of the change.

Accordingly, the changes in 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.

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This evaluation includes reviewing a counterparty’s credit rating and latest financial information.

As of December 31, 2024, the Partnership had seven counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under the Credit Facility.

As of December 31, 2025, the Partnership had eight counterparties, all of which are lenders under the Credit Facility.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tables below summarize the fair value and classification 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:

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(in thousands)

Current asset Commodity derivative assets $ 4,866 $ ( 3,042 ) $ 1,824

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

Current liability Commodity derivative liabilities $ 6,894 $ ( 3,042 ) $ 3,852

Long-term liability Commodity derivative liabilities 12,349 ( 768 ) 11,581

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 ) $ —

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(in thousands)

Current asset Commodity derivative assets $ 41,485 $ ( 3,212 ) $ 38,273

Current asset Commodity derivative assets, net $ 4,866 $ ( 3,042 ) $ 1,824

Long-term asset Deferred charges and other long-term assets 768 ( 768 ) —

Total assets $ 5,634 $ ( 3,810 ) $ 1,824

Current liability Commodity derivative liabilities $ 4,441 $ ( 3,212 ) $ 1,229

Long-term liability Commodity derivative liabilities 207 ( 126 ) 81

Current liability Commodity derivative liabilities, net $ 6,894 $ ( 3,042 ) $ 3,852

Long-term liability Commodity derivative liabilities, net 12,349 ( 768 ) 11,581

Total liabilities $ 19,243 $ ( 3,810 ) $ 15,433

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented:

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:

For the year ended December 31,

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Ending fair value of commodity derivative instruments $ 22,993 $ ( 13,609 ) $ 37,335

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for oil as of December 31, 2025:

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Fourth quarter 180 59.56 58.85 60.10

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for natural gas as of December 31, 2025:

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Fourth quarter 6,440 3.93 3.85 4.00

The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2024:

Volume (BBtu) Weighted Average Price (per MMBtu) Range (per MMBtu)

The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2025:

Volume (MBbl) Weighted Average Price (per MMBtu) Range (per MMBtu)

Period and Type of Contract Low High

Natural Gas Swap Contracts:

Oil Swap Contracts:

First quarter 150 $ 59.74 $ 58.13 $ 61.20

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NOTE 6 — FAIR VALUE MEASUREMENTS

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date.

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.

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The estimated carrying value of all debt as of December 31, 2025 and 2024 approximated the fair value due to variable market rates of interest.

These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available.

The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows.

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The Partnership has designated these measurements as Level 3.

The Partnership's fair value assessments for recent acquisitions are included in Note 4 — Oil and Natural Gas Properties.

Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment.

The Partnership had no business combinations for the years ended December 31, 2025 and 2024.

See "Note 4 — Oil and Natural Gas Properties." The Partnership's fair value assessments for recent acquisitions are included in "Note 4 — 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.

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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 fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

The 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 have been determined at discrete points in time based on relevant market 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 years ended December 31, 2025 and 2024.

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2024 and 2023.

NOTE 7 — SIGNIFICANT CUSTOMERS

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended December 31, 2025 and 2024.

NOTE 7 — SIGNIFICANT OPERATORS

The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable.

Pioneer Natural Resources and XTO Energy, subsidiaries of ExxonMobil Corporation, represented approximately 13 % of total oil and natural gas revenues for the year ended December 31, 2024, no single customer exceeded 10 % of total oil and natural gas revenues for the year ended December 31, 2023 , and XTO Energy represented approximately 12 % of total oil and natural gas revenues for the year ended December 31, 2022.

If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests.

The loss of any single customer is mitigated by the Partnership’s diversified customer base.

For the year ended December 31, 2025, Aethon represented approximately 14 % of total oil and natural gas revenues.

For the year ended December 31, 2024, Pioneer Natural Resources and XTO Energy, subsidiaries of ExxonMobil Corporation, collectively represented 13 % of total oil and natural gas revenues.

No single operator exceeded 10% of total oil and natural gas revenues for the year ended December 31, 2023.

If the Partnership lost a significant operator on its properties, such loss could impact revenue derived from its mineral and royalty interests and working interests.

The loss of any single operator is mitigated by the Partnership’s diversified operator base.

NOTE 8 — CREDIT FACILITY

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The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations.

The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10 % of the value of the borrowing base immediately prior to such acquisition.

The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5 % of the current borrowing base.

In these circumstances, the borrowing base will be adjusted by

The Partnership also has the right to request a redetermination following the acquisition of

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $ 550.0 million.

The subsequent redeterminations increased the borrowing base to $ 580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024.

After each redetermination we elected to maintain cash commitments at $ 375.0 million.

oil and natural gas properties in excess of 10 % of the value of the borrowing base immediately prior to such acquisition.

The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5 % of the current borrowing base.

In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base.

The borrowing base was reaffirmed in April 2024, November 2024 and April 2025 at $ 580.0 million.

After each redetermination the Partnership elected to maintain cash commitments at $ 375.0 million.

In October 2025, the Partnership amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and reduce the adjustment applied to secured overnight financing rate ("SOFR") loans.

Concurrent with the Credit Facility amendment, the borrowing base was reaffirmed at $ 580.0 million and the Partnership elected to maintain cash commitments at $ 375.0 million.

All existing banks in the lender syndicate elected to continue participating in the Credit Facility.

No other significant terms were changed as part of the amendment.

The next semi-annual redetermination is scheduled for April 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 secured overnight financing rate ("SOFR") loan or a base-rate loan.

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 December 31, 2023 and December 31, 2024 and, 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 %.

As of December 31, 2024 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 7.50 % during the twelve months ended December 31, 2024 and the weighted-average interest rate was 7.36 % as of December 31, 2023.

The weighted-average interest rate of the Credit Facility was 7.03 % during the year ended December 31, 2025 and the weighted-average interest rate was 7.50 % during the year ended December 31, 2024.

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.

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As of December 31, 2025, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $ 25.0 million and zero at December 31, 2024 and 2023, respectively.

The aggregate principal balance outstanding was $ 154.0 million and $ 25.0 million at December 31, 2025 and 2024, respectively.

The unused portion of the available borrowings under the Credit Facility was $ 221.0 million and $ 350.0 million at December 31, 2025 and 2024, respectively.

NOTE 9 — INCENTIVE COMPENSATION

The board of directors of the Partnership’s general partner (the "Board") established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to the Partnership’s common units.

The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards.

Any vesting terms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof.

Incentive compensation expense is included in the General and administrative line item on the consolidated statements of operations.

The total compensation expense related to common unit grants is measured as the number of units granted multiplied by the grant-date fair value per unit.

Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the award agreements over the requisite service periods (generally equivalent to the vesting period) with actual forfeitures recognized as they occur.

The board of directors of the Partnership’s general partner (the "Board") previously established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates were eligible to receive awards with respect to the Partnership’s common units.

The 2015 LTIP provided for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards.

Any vesting terms associated with incentive awards granted under the 2015 LTIP were based on a predetermined schedule as approved by the Board or a committee thereof.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2025, the Board approved the adoption of a new long-term incentive plan to replace the 2015 LTIP following its expiration, which allows for the grant of the same type of awards and to the same service providers as was provided for under the 2015 LTIP.

On June 12, 2025, our unitholders approved the Board’s adoption of the Black Stone Minerals, L.P.

2025 Long Term Incentive Plan (the “2025 LTIP”) at the Partnership’s 2025 Annual Meeting.

Following the unitholder approval of the 2025 LTIP, no further awards will be granted under the 2015 LTIP.

which expired on May 6, 2025, but which will continue to govern awards previously granted and still outstanding as of such expiration date.

Incentive compensation expense is included in the General and administrative line item on the consolidated statements of operations.

The total compensation expense related to common unit grants is measured as the number of units granted multiplied by the grant-date fair value per unit.

The Partnership also provides cash incentives in the form of an annual short-term incentive bonus for its executive officers and other employees.

These awards are payable based on employee performance and the achievement of annual financial objectives measured against our internal operating plan established at the beginning of each fiscal year.

However, final payouts are subject to reduction or increase by the Compensation Committee for individual and team performance during the performance period.

However, final payouts are subject to reduction or increase by the Compensation Committee of the Board (the "Compensation Committee") for individual and team performance during the performance period.

Restricted Unit Awards

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The grant-date fair value of these awards is recognized ratably using the straight-line attribution method.

The Compensation Committee of the Board (the "Compensation Committee") annually approves a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees.

The Compensation Committee annually approves a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees.

Consistent with previous awards the 2025 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2028.

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The Compensation Committee also approves grants of restricted performance units that are subject to both performance-based and service-based vesting provisions.

The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Partnership’s performance over each of the three calendar year performance periods commencing January 1 of the first calendar period.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

over each of the three calendar year performance periods commencing January 1 of the first calendar period.

The target number of common units subject to each restricted performance unit is one ;

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Distribution equivalent rights for the restricted performance unit awards are charged to partners’ capital.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about performance units for the year ended December 31, 2025.

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In the first quarter of 2022, the Board approved a grant of awards to all employees dependent on the achievement of an aspirational production target to be measured in the fourth quarter of 2025 (the "Aspirational Awards").

The Aspirational Awards include performance cash awards and performance equity awards in the form of restricted performance units.

To the extent earned, each performance unit represents the right to receive one common unit.

The performance cash awards and performance units are eligible to become earned at the end of the requisite service period on December 31, 2025 if the minimum performance metrics are achieved.

The minimum performance metrics are at least 42 Mboe per day of average daily royalty production in either the fourth quarter or the month of December of 2025 while maintaining a net debt to EBITDA ratio less than or equal to 1.0 on December 31, 2025.

Average daily royalty production does not include production attributable to acquisitions consummated during the performance period.

The following table summarizes information about the aspirational performance units for the year ended December 31, 2024.

Aspirational Performance units Number of Units Weighted-Average Grant-Date

Fair Value per Unit

Unvested at December 31, 2023 1,273,513 $ 12.06

Granted 18,891 15.88

Forfeited ( 184,237 ) 11.84

Unvested at December 31, 2024 1,108,167 $ 12.16

Total compensation expense to be recognized over the life of the Aspirational Awards consists of $ 5.3 million for the performance cash awards and $ 13.5 million for the performance equity awards.

Compensation expense related to the Aspirational Awards will be recorded over the service period when achievement of the performance condition is probable.

As of December 31, 2024, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Aspirational Awards included performance cash awards and performance equity awards in the form of restricted performance units.

The awards were contingent on achieving a production target of at least 42 Mboe per day of average daily royalty production in the fourth quarter or December 2025.

As the production target was not met, all awards were forfeited, and no compensation expense was recognized for the year ended December 31, 2025.

Incentive Compensation Expense

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Total incentive compensation expense $ 14,673 $ 13,504 $ 15,271

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — EMPLOYEE BENEFIT PLANS

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federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements and no provision for potential remediation costs has been recorded.

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 consolidated financial statements, and no provision for potential remediation costs has been recorded.

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

The Partnership believes existing claims as of December 31, 2025 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

NOTE 12 — 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 to the Purchaser for a cash purchase price of $ 20.39 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $ 300 million.

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 $ 300.0 million.

The Series B cumulative convertible preferred units were initially entitled to quarterly distributions in an amount equal to 7.0 % of the face amount of the preferred units per annum (the “Distribution Rate”).

On November 28, 2023, the Distribution Rate was adjusted to 9.8 % and will be readjusting every two years thereafter (each, a “Readjustment Date”).

The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5 % per annum;

The Distribution Rate adjusted on November 28, 2023 and will be readjusted every two years thereafter (each, a “Readjustment Date”).

The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5 % per annum;

provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0 % per annum for such quarter.

The Distribution Rate was adjusted to 9.8 % effective November 28, 2023 and remained the same at 9.8 % for November 28, 2025.

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 $ 10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.

The Partnership has the option to redeem all or a portion (equal to or greater than $ 100.0 million) of the Series B cumulative convertible preferred units at par within a 90-day period beginning on November 28, 2025, and each second anniversary thereafter.

The Series B cumulative convertible preferred units had a carrying value of $ 300.5 million, including accrued distributions of $ 7.4 million, as of December 31, 2024 and a carrying value of $ 299.1 million, including accrued distributions of $ 6.0 million as of December 31, 2023.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $ 100.0 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 December 31, 2025 and 2024.

The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain redemption provisions are outside the control of the Partnership.

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(in thousands, except per unit amounts)

NET INCOME (LOSS) $ 271,326 $ 422,549 $ 476,480

NET INCOME $ 299,932 $ 271,326 $ 422,549

Distributions on Series B cumulative convertible preferred units ( 29,466 ) ( 29,466 ) ( 21,776 )

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 241,860 $ 400,773 $ 455,480

ALLOCATION OF NET INCOME (LOSS):

NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 270,466 $ 241,860 $ 400,773

ALLOCATION OF NET INCOME:

General partner interest $ — $ — $ —

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$ 270,466 $ 241,860 $ 400,773

Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 241,860 $ 400,773 $ 455,480

Numerator for basic EPU - net income attributable to common unitholders $ 270,466 $ 241,860 $ 400,773

Effect of dilutive securities — — 21,776

Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 241,860 $ 422,549 $ 476,480

Numerator for diluted EPU - net income attributable to common unitholders after the effect of dilutive securities $ 270,466 $ 241,860 $ 422,549

Denominator for basic EPU - weighted average common units outstanding (basic) 211,667 210,684 209,970

Effect of dilutive securities

96 15,135 15,064

Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 211,729 210,780 225,105

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:

NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:

Per common unit (basic) $ 1.28 $ 1.15 $ 1.91

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The partnership agreement generally provides that any distributions are paid each quarter in the following manner:

• first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7.0 % of the face amount of the preferred units per annum, through November 27, 2023, then adjusting on November 28, 2023 and readjusting every two years thereafter, to a rate equal to the greater of (i) the rate in effect immediately prior to the relevant readjustment and (ii) the 10-year Treasury Rate as of such readjustment date plus 5.5 % per annum (which rate adjusted to 9.8 % effective November 28, 2023 and remained the same at 9.8 % for November 28, 2025 and

• second , to the holders of common units.

The following table provides information about the Partnership's per unit distributions to common unitholders:

Year Ended December 31,

2024 2023 2022

Distributions declared and paid per common unit $ 1.60 $ 1.90 $ 1.54

Common Unit Repurchase Program

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Distributions will be paid on February 25, 2026 to unitholders of record at the close of business on February 18, 2026.

Subsequent to December 31, 2024, the Partnership acquired mineral and royalty interests from various sellers for cash consideration of $ 5.4 million.

These acquisitions were funded with cash from operating activities and borrowings under the Credit Facility.

BLACK STONE MINERALS, L.P.

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1 Unproved properties include purchases of leasehold prospects.

Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements.

See "Note 4 – Oil and Natural Gas Properties" for additional information.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property.

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119 ( 25,218 ) ( 4,084 )

Purchases of minerals in place 3

Sales of minerals in place 4

( 163 ) ( 1,250 ) ( 371 )

Extensions, discoveries and other additions 2

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Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.

There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes.

The Partnership is subject to certain state based taxes;

however, these amounts are not material.

There are no federal income taxes deducted in the calculation of the standardized measure because the Partnership is not subject to them.

Future income tax expense includes applicable state taxes.

See "Note 2 – Summary of Significant Accounting Policies" for additional information.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures