What changed in this filing

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Item 9A. Controls and Procedures

2025-02-25 compared with 2024-02-20 · 152 added, 200 removed, 1039 unchanged (25% of the section changed)

19 unchanged sentences

Information required by this item and not otherwise provided below is incorporated by reference to the material appearing in our Proxy Statement for the 2025 Annual Meeting of Limited Partners (“2025 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2024.

The following table shows information for the executive officers and directors of the General Partner.

The following table shows information for the executive officers and directors of the General Partner as of February 25, 2025.

Executive officers serve at the discretion of the Board.

Directors hold office until their successors are duly elected and qualified.

There are no family relationships among any of our directors or executive officers.

Name Age Position With The General Partner

73 Chairman, Chief Executive Officer, and President

Kiefer 36 Senior Vice President, Chief Financial Officer and Treasurer

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

Steve Putman 49 Senior Vice President, General Counsel, and Secretary

Clark 47 Senior Vice President, Land & Commercial

Smajstrla 53 Vice President and Chief Accounting Officer

Clark 48 Senior Vice President, Chief Commercial Officer

Carter 45 Senior Vice President, Corporate Development

Bonner 35 Vice President and Chief Accounting Officer

Barth 62 Director

52 unchanged sentences

(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.

Fourth 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, Bank of America, N.A.

and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A.

DBA and Amegy Bank National Association, as Documentation Agent, and the lenders signatory thereto, dated as of November 1, 2017 (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 7, 2017 (SEC File No.

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

and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders dated as of February 7, 2018.

Second Amendment to Fourth 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 a syndicate of lenders dated as of October 31, 2018 (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 5, 2018 (SEC File No.

Third Amendment to Fourth 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 a syndicate of lenders dated as of May 1, 2020.

Fourth Amendment to Fourth 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 a syndicate of lenders dated as of November 3, 2020.

Fifth Amendment to Fourth 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 a syndicate of lenders dated as of April 30, 2021.

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

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.

3 unchanged sentences

333-202875)).

10.11 ^*

Form of Severance Agreement for Senior Vice Presidents

Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 20, 2024 (SEC File No.

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 10.12 to

Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 23, 2023 (SEC File No.

333-202875)).

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 23, 2023 (SEC File No.

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 10.13

to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 23, 2023 (SEC File No.

333-202875)).

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 23, 2023 (SEC File No.

Form of STI Award Letter (Leadership) under the Black Stone Minerals, L.P.

Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.17 of Black Stone Minerals, L.P.'s Annual Report on Form 10-K filed on February 28, 2018 (SEC File No.

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 ^

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.

10.1 3 ^

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.

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

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(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.

Separation Agreement and General Release of Claims, dated as of March 2, 2023, by and among Jeffrey

Wood, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, 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 March 3, 2023).

Black Stone Minerals, L.P.

Insider Trading Policy.

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

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Black Stone Minerals, L.P.

Incentive-Based Compensation Recoupment Policy, adopted as of October 18, 2023.

Incentive-Based Compensation Recoupment Policy, adopted as of October 18, 2023 (incorporated herein by reference to Exhibit 97.1 to Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 20, 2024 (SEC File No.

Report of Netherland, Sewell & Associates, Inc.

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(Principal Executive Officer)

Kiefer Senior Vice President, Chief Financial Officer and Treasurer February 20, 2024

Kiefer (Principal Financial Officer)

Smajstrla Vice President and Chief Accounting Officer February 20, 2024

Smajstrla (Principal Accounting 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)

Barth Director February 25, 2025

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Report of Independent Registered Public Accounting Firm

To the Audit Committee of the Board of Directors and Unitholders of

Black Stone Minerals, L.P.

and subsidiaries

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

Opinion on the Financial Statements

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

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that:

(1) relate 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate .

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

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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.

Subjective 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 the selection of inputs, including historical production, oil and natural gas price assumptions, future operating costs assumptions and tax rates by jurisdiction, among others.

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 over its process to calculate oil and natural gas properties DD&A, including management’s controls over the accuracy of the financial data provided to the engineers for use 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 evaluating corroborative and contrary evidence.

We also tested the mathematical accuracy of the oil and natural gas properties DD&A calculation, including comparing the proved oil and natural gas reserves amounts used in the calculation to the Partnership’s reserves report.

Revenues from Contracts with Customers Accrual

Description of

At December 31, 2023, the Partnership had $77.6 million in accrued revenues from contracts with customers.

As discussed in Note 2, the Partnership records revenue in the month production is delivered to the purchaser.

As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered.

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 consolidated balance sheets.

Auditing the Partnership’s revenues from contracts with customers accrual is complex and judgmental because it involves the evaluation of subjective management inputs and assumptions used in the calculation.

Additionally, auditing the revenues from contracts with customers accrual is challenging because the Partnership’s mineral and royalty interests include ownership in a significant amount of producing wells.

How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s process to estimate the revenues from contracts with customers accrual, including management’s controls over the significant assumptions and completeness and accuracy of the data used in the calculation.

Our audit procedures included, among others, testing the significant inputs to the calculation of the revenues from contracts with customers accrual by evaluating corroborative and contrary evidence.

These inputs included oil and natural gas price assumptions and production estimates.

Additionally, we assessed the historical accuracy of the revenues from contracts with customers accrual through lookback procedures.

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

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Report of Independent Registered Public Accounting Firm

To the Audit Committee of the Board of Directors and Unitholders of

Black Stone Minerals, L.P.

and subsidiaries

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

Opinion on Internal Control Over Financial Reporting

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(in thousands)

Common units Partners' equity

BALANCE AT DECEMBER 31, 2021 208,666 $ 765,268

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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 —

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Equity-based compensation 8,564 10,829 17,388

Exploratory dry hole expense — — 1,048

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

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Segment Reporting

The Partnership operates in a single operating and reportable segment.

Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance.

The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

The Partnership operates in a single reportable 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.

These properties are all located within the continental U.S., including all of the major onshore producing basins.

Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker ("CODM") in deciding how to allocate resources and assess performance.

The Partnership’s 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 measure of segment assets is reported on the consolidated balance sheets as total assets.

The CODM uses net income to evaluate the income generated from segment assets in deciding whether to reinvest profits into the Partnership's oil and natural gas properties or for other activities such as distributions to unitholders and reducing outstanding borrowings as applicable.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

There are numerous uncertainties inherent in estimating quantities of proved oil and

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

natural gas reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves.

The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative instruments are recognized at fair value.

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Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership maintains cash and cash equivalent balances with major financial institutions.

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Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred.

Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date.

Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts.

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DD&A expense related to the Partnership’s producing oil and natural gas properties was $ 44.8 million, $ 45.0 million, and $ 47.2 million for the years ended December 31, 2024, 2023, and 2022, respectively.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

There was no impairment of proved or unproved oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021.

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

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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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Property and Equipment

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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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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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Right-of-use ("ROU") assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease.

ROU assets are recognized

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives.

ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives.

Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term.

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As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership recognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.

The Partnership records revenue in the month production is delivered to the purchaser.

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 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.

Lease bonus and other income

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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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease bonus and other income

Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser.

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 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.

For the years ended December 31, 2023 and 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

The Partnership is organized as a pass-through entity for income tax purposes.

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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, and accounts payable, approximate their fair value at December 31, 2023 and 2022 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, 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.

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

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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.

The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

The Partnership does not plan to early adopt and expects the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures.

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.

The guidance is effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027, with early adoption permitted.

The Partnership is currently evaluating the impact of this standard on its disclosures.

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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NOTE 4 — OIL AND NATURAL GAS PROPERTIES

The Partnership had no material divestiture activity during 2023 and 2022.

In the third quarter of 2021, the Partnership closed on the divestiture of its wholly owned subsidiary, TLW Investments, L.L.C.

("TLW"), effective September 1, 2021 for total proceeds of $ 0.2 million.

TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas.

TLW's assets and liabilities consisted of oil and natural gas properties with a net book value of $ 3.0 million and asset retirement obligations with a book value of $ 5.7 million at the time of sale.

The Partnership recognized a $ 2.9 million gain associated with the divestiture included in the (Gain) loss on sale of assets , net line item of the consolidated statement of operations for the year ended December 31, 2021.

Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date.

Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

2023 Acquisitions

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.

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.

2022 Acquisitions

The Partnership had no material acquisition activity during 2022.

2021 Acquisitions

In May 2021, the Partnership closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $ 20.8 million.

The purchase price consisted of $ 10.0 million in cash and $ 10.8 million in common units of the Partnership.

The cash consideration was funded with borrowings under the Credit Facility (as defined in Note 8 - Credit Facility) and funds from operating activities.

The transaction was accounted for as a business combination with the assets acquired recorded at their estimated fair values as of the acquisition date.

The assets acquired consisted of $ 4.9 million of proved oil and natural gas properties, $ 15.6 million of unproved oil and natural gas properties, and $ 0.3 million of net working capital.

Acquisition related costs of $ 0.3 million were expensed and included in the General and administrative line of the consolidated statement of operations for the year ended December 31, 2021.

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 lower its capital spending other than for mineral and royalty interest acquisitions.

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

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

San Augustine Farmout

In March 2021, BSM and XTO reached an agreement to partition jointly owned working interests in the Brent Miller development area in San Augustine County.

Under the partition agreement, BSM and XTO exchanged working interests in certain existing and proposed drilling units, resulting in each company holding 100 % of the working interests in their respective partitioned units.

In May 2021, BSM and Aethon Energy ("Aethon") entered into an agreement to develop certain of the Partnership's undeveloped acreage in San Augustine County, including the working interests resulting from the partition agreement discussed

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.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract area.

The agreement calls for a minimum of five wells to be drilled in the initial program year, which began in the third quarter of 2021, 10 wells to be drilled in the second and third program years, and, thereafter, a minimum of 12 wells per year beginning with the fourth program year.

The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County discussed below.

In May 2021, the Partnership entered into a new 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").

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 cover all of the Partnership's working interests under active development by Aethon in San Augustine County, Texas and continue for a 10 year period, unless earlier terminated in accordance with the terms of the agreements.

Canaan, Azul, and JWM will each earn a percentage of the Partnership's working interest in wells drilled and operated by Aethon within the contract area subject to the agreements.

Canaan, Azul, and JWM were obligated to fund the development of wells drilled by Aethon in the initial program year, and thereafter, have certain rights and options to continue funding the Partnership's working interest for the duration of each farmout agreement.

The Partnership will receive an overriding royalty interest ("ORRI") before payout and, in most cases, an increased ORRI after payout on all wells drilled under the farmout agreements.

As of December 31, 2023, 17 wells had been spud in the contract area subject to the Canaan, Azul, and JWM Farmouts.

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

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

Canaan 64.0 % 32.0 %

Former Canaan Interest 64.0 % 32.0 %

Azul 20.0 % 10.0 %

JWM 16.0 % 8.0 %

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

Canaan 40.0 % 10.0 %

Former Canaan Interest 40.0 % 10.0 %

Azul 50.0 % 12.5 %

JWM 10.0 % 2.5 %

Former JWM Interest 10.0 % 2.5 %

Total 100.0 % 25.0 %

Angelina Farmout

In May 2020, the Partnership entered into a development agreement with Aethon to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas.

The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area.

The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, 10 wells to be drilled in the second program year, and, beginning with the third program year, 15 wells per year beginning thereafter.

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

The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement.

Pivotal will earn 100 % of the Partnership's working interest (ranging from approximately 12.5 % to 25 % on an 8/8ths basis) in wells drilled and operated by

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Aethon within the contract area subject to the agreement.

Pivotal was obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Pivotal Farmout.

Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group.

As of December 31, 2023, a total of 45 wells have been spud in the contract area subject to the Pivotal Farmout.

Aethon Time-Out

In December 2023, the Partnership received notice that Aethon was exercising the "time-out" provisions under its joint exploration agreements with BSM in Angelina and San Augustine counties in East Texas.

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

The current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months.

Aethon has not previously invoked the time-out provisions under the agreements.

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.

Impairment of Oil and Natural Gas Properties

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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.

No impairment of oil and natural gas properties was recognized for the years ended December 31, 2023, 2022, and 2021.

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.

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 financial instruments.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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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.

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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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Total liabilities $ 4,648 $ ( 3,338 ) $ 1,310

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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:

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Ending fair value of commodity derivative instruments $ ( 13,609 ) $ 37,335 $ 28,941

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AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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Fourth quarter 555 71.22 70.02 73.15

First quarter 180 66.29 65.52 67.35

Second quarter 180 66.29 65.52 67.35

Third quarter 180 66.29 65.52 67.35

Fourth quarter 180 66.29 65.52 67.35

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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Fourth quarter 11,040 3.45 3.34 3.65

The Partnership had the following open derivative contracts for oil subsequent to December 31, 2023:

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

Period and Type of Contract Low High

Oil Swap Contracts:

First quarter 9,000 $ 3.55 $ 3.50 $ 3.68

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Fourth quarter 9,200 3.55 3.50 3.68

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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Fourth quarter 1,840 4.05 4.05 4.05

First quarter 900 3.65 3.65 3.65

Second quarter 910 3.65 3.65 3.65

Third quarter 920 3.65 3.65 3.65

Fourth quarter 920 3.65 3.65 3.65

BLACK STONE MINERALS, L.P.

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

XTO Energy represented approximately 12 % and 19 % of total oil and natural gas revenue for the years ended December 31, 2022 and 2021, respectively.

No customer exceeded 10% of total oil and natural gas revenue for the year ended December 31, 2023.

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.

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The Partnership maintains a senior secured revolving credit agreement, as amended, (the “Credit Facility”).

The Credit Facility has an aggregate maximum credit amount of $ 1.0 billion.

The Credit Facility has an aggregate maximum credit amount of $ 1.0 billion and terminates on October 31, 2027.

The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time.

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

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

In these circumstances, the borrowing base will be adjusted by

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2022, the Partnership revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027.

Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $ 550.0 million and the Partnership elected to lower commitments under the Credit Facility from $ 400.0 million to $ 375.0 million.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $ 550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $ 580.0 million.

After both redeterminations the Partnership elected to maintain cash commitments at $ 375.0 million.

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.

The next semi-annual redetermination is scheduled for April 2025.

In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR").

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50 %, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00 %) or Adjusted Term SOFR, in each case, plus the applicable margin.

As of December 31, 2023 and 2022, the alternative base rate margin ranged from 1.50 % to 2.50 % and the Adjusted Term SOFR margin ranged from 2.50 % to 3.50 % depending on the borrowings outstanding in relation to the borrowing base.

The Partnership’s borrowings under the Credit Facility bear interest at a floating rate determined by the type of loan the Partnership has elected to take:

a secured overnight financing rate ("SOFR") loan or a base-rate loan.

Both types of loans bear interest at a reference rate plus a margin that varies with the amount of borrowings outstanding under the Credit Facility.

The reference rate for SOFR loans is equal to SOFR as published by the Federal Reserve Bank of New York, adjusted for the borrowing term, plus 2.50 %, which is referred to as Adjusted Term SOFR.

The reference rate for base rate loans is the highest of (a) Wells Fargo’s prime commercial lending rate for that day, (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 %.

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.

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Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0 :1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5 :1.0.

Distributions are not permitted if there is a default under the credit agreement (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10 % of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0 .

Distributions are not permitted if there is a default under the Credit Facility (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10 % of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0 .

As of December 31, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.

At December 31, 2023, there was no aggregate principal balance outstanding and the aggregate principal balance outstanding at December 31, 2022 was $ 10.0 million.

The unused portion of the available borrowings under the Credit Facility were $ 375.0 million and $ 365.0 million at December 31, 2023 and 2022, respectively.

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

The unused portion of the available borrowings under the Credit Facility was $ 350.0 million and $ 375.0 million at December 31, 2024 and 2023, respectively.

NOTE 9 — INCENTIVE COMPENSATION

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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

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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.

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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 until February 26, 2024 at a redemption price of $ 21.41 per Series B cumulative convertible preferred unit, which is equal to 105 % of par value.

Thereafter, the Partnership may redeem the Series B cumulative convertible preferred units at par within a 90-day period on each second anniversary following November 28, 2023.

The 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.

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NOTE 15 — SUBSEQUENT EVENTS

On January 31, 2024, the Board approved a distribution for the period from October 1, 2023 to December 31, 2023 of $ 0.475 per common unit.

On February 5, 2025, the Board approved a distribution for the period from October 1, 2024 to December 31, 2024 of $ 0.375 per common unit.

Distributions will be paid on February 25, 2025 to unitholders of record at the close of business on February 18, 2025.

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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Unproved 107,537 14,605 149

Exploration Costs — — 1,049

Development Costs 1

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1,422 6,455 2,498

Purchases of minerals in place 2

Sales of minerals in place 4

( 135 ) ( 6,194 ) ( 1,167 )

Extensions, discoveries and other additions 2

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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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The most notable revisions are related to changes in commodity pricing.

2 Includes the acquisition of mineral and royalty reserves.

In 2021 these were primarily in the Permian Basin.

2 Includes extensions and additions related to drilling activities in multiple areas, primarily within the Haynesville/Bossier play trend and the Permian Basin.

4 Includes divestitures of mineral and royalty reserves.

In 2021 these were primarily in the Anadarko Basin.

3 Includes the acquisition of mineral and royalty reserves primarily within the Haynesville/Bossier play trend.

4 Includes divestitures of working interest reserves primarily within the Austin Chalk play trend.

BLACK STONE MINERALS, L.P.

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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