What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2024-02-20 compared with 2023-02-23 · 178 added, 158 removed, 1061 unchanged (24% of the section changed)

2 unchanged sentences

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report.

Our disclosure

controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC.

Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC.

Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023 to provide such reasonable assurance.

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OTHER INFORMATION

During the three months ended December 31, 2023, 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.

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Information required by this item is incorporated by reference to the material appearing in our Proxy Statement for the 2023 Annual Meeting of Limited Partners (“2023 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2022.

Information required by this item and not otherwise provided below is incorporated by reference to the material appearing in our Proxy Statement for the 2024 Annual Meeting of Limited Partners (“2024 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2023.

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

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

72 Chairman, Chief Executive Officer, and President

Kiefer 36 Senior Vice President, Chief Financial Officer and Treasurer

Steve Putman 48 Senior Vice President, General Counsel, and Secretary

Clark 47 Senior Vice President, Land & Commercial

Smajstrla 53 Vice President and Chief Accounting Officer

Barth 61 Director

Mark DeWalch 62 Director

Linn 72 Director

Longmaid 78 Director

Mathis 57 Director

Randall 57 Director

Stuart 73 Director

Whitehead 48 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.

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333-202875)).

Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No.

333-202875)).

10.11 ^*

Form of Severance Agreement for Senior Vice Presidents

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

Long-Term Incentive Plan

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)).

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

Long-Term Incentive Plan

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)).

Form of STI Award Letter (Leadership) under the 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).

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

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Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Black Stone Minerals, L.P.

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

Report of Netherland, Sewell & Associates, Inc.

18 unchanged sentences

/s/ Thomas L.

Chief Executive Officer and Chairman February 22, 2023

President, Chief Executive Officer and Chairman February 20, 2024

(Principal Executive Officer)

/s/ Jeffrey P.

Wood President and Chief Financial Officer February 22, 2023

Wood (Principal Financial 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

12 unchanged sentences

Stuart Director February 20, 2024

/s/ Allison K.

Thacker Director February 22, 2023

Whitehead Director February 20, 2024

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

36 unchanged sentences

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 estimated by independent petroleum engineers.

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

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.

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

Estimating proved oil and natural gas reserves also requires the selection of inputs, including oil and natural gas price assumptions, future operating costs assumptions and tax rates by jurisdiction, among others.

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.

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, 2023.

Auditing the Partnership’s 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 estimating 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 DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and natural gas reserves.

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.

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 completeness and accuracy of the financial data and inputs described above used by the engineers in estimating proved oil and natural gas reserves by evaluating corroborative and contrary evidence.

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

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

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Depreciation, depletion, and amortization 45,683 47,804 61,019

Impairment of oil and natural gas properties — — 51,031

General and administrative 51,455 53,652 48,746

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Per common unit (diluted) $ 1.88 $ 2.12 $ 0.77

$ 2.12 $ 0.77 $ 0.49

WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:

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Weighted average common units outstanding (diluted) 225,105 224,446 208,290

1 For the year ended December 31, 2022 diluted net income (loss) attributable to common units included distributions on Series B cumulative convertible preferred units of $ 21 million.

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

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AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY (in thousands)

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)

BALANCE AT DECEMBER 31, 2020 206,749 $ 760,606 $ 760,606

Conversion of Series A redeemable preferred units

Repurchases of common units ( 223 ) ( 1,957 ) ( 1,957 )

Issuance of common units for property acquisitions 1,087 10,766 10,766

Restricted units granted, net of forfeitures 1,053 — —

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Repurchases of common units ( 262 ) ( 2,991 ) ( 2,991 )

Issuance of common units for property acquisitions 1,087 10,766 10,766

Restricted units granted, net of forfeitures 1,003 — —

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Depreciation, depletion, and amortization 45,683 47,804 61,019

Impairment of oil and natural gas properties — — 51,031

Accretion of asset retirement obligations 1,042 861 1,073

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CASH FLOWS FROM FINANCING ACTIVITIES

Distributions to common and subordinated unitholders ( 322,403 ) ( 176,924 ) ( 140,343 )

Distributions to common unitholders ( 398,824 ) ( 322,403 ) ( 176,924 )

Distributions to Series B cumulative convertible preferred unitholders ( 21,000 ) ( 21,000 ) ( 21,000 )

Repurchases of common and subordinated units ( 2,991 ) ( 1,957 ) ( 5,035 )

Repurchases of common units ( 5,496 ) ( 2,991 ) ( 1,957 )

Borrowings under credit facility 64,000 339,000 212,000

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The Partnership’s reserve estimates are determined by an independent petroleum engineering firm.

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards.

Other items subject to estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards.

The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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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 further discussion.

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

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

however, the Partnership monitors the creditworthiness of its counterparties.

See Note 5 – Commodity Derivative Financial Instruments for further discussion.

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

Oil and Natural Gas Properties

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DD&A expense related to the Partnership’s producing oil and natural gas properties was $ 45.0 million, $ 47.2 million, and $ 60.4 million for the years ended December 31, 2023, 2022, and 2021, respectively.

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

This evaluation is performed on a depletable unit basis.

The Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability.

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

The factors used to determine 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.

There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the

same time demand weakened due to the impact of the COVID-19 pandemic.

The Partnership determined these events and

circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and

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.

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

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.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired.

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

The Partnership recognized $ 51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020.

See Note 6 - Fair Value Measurements for further discussion.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value 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.

There was no impairment of unproved properties for the years ended December 31, 2022, 2021, and 2020.

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

Other Property and Equipment

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Amortization expense for debt issuance costs was $ 1.0 million, $ 2.0 million, and $ 1.6 million for the years ended December 31, 2023, 2022, and 2021, respectively, and is included in interest expense in the consolidated statements of operations.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

6 unchanged sentences

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 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

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.

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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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.

Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

executed, such that revenue is recognized when the lease bonus payment is received.

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.

At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606.

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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

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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.

See Note 6 – Fair Value Measurements for further discussion.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Incentive Compensation

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

See Note 9 – Incentive Compensation for additional discussion.

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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.

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

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

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

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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Non-current asset retirement obligations $ 19,030 $ 15,030

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4 — OIL AND NATURAL GAS PROPERTIES

The Partnership had no material divestiture activity during 2022.

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.

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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.

In the third quarter of 2020, the Partnership closed two separate divestitures of certain mineral and royalty properties in the Permian Basin for total proceeds, after final closing adjustments, of $ 150.6 million.

One of these transactions, effective May 1, 2020, involved the sale of the Partnership's mineral and royalty interest in specific tracts in Midland County, Texas for net

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

proceeds of approximately $ 54.5 million.

The other transaction, effective July 1, 2020, involved the sale of an undivided interest across parts of the Partnership's Delaware Basin and Midland Basin positions for net proceeds of approximately $ 96.1 million.

The total book value of the assets divested through these transactions was $ 126.6 million at the time of sale.

The Partnership recognized a $ 24.0 million gain associated with the divestitures included in the (Gain) loss on sale of assets, net line item of the consolidated statement of operations for the year ended December 31, 2020.

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 Partnership had no material acquisition activity during 2022 and 2020.

2023 Acquisitions

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.

7 unchanged sentences

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.

In 2017, the Partnership entered into farmout arrangements with Canaan Resource Partners ("Canaan") and Pivotal Petroleum Partners ("Pivotal") in the Shelby Trough area of East Texas where the Partnership owns a concentrated, relatively high-interest royalty position.

This area was under active development by XTO Energy Inc.

("XTO") in San Augustine County, Texas and BPX Energy in Angelina County, Texas through 2019.

These farmout agreements were superseded and replaced by the new farmout agreements discussed below.

San Augustine Farmout

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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 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, ten wells to be drilled in the second and third program years, and, thereafter, a minimum of twelve 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").

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Augustine County, Texas and continue for a ten year period, unless earlier terminated in accordance with the terms of the agreements.

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.

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.

1 unchanged sentence

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, 2022, ten wells had been spud in the contract area subject to the Canaan, Azul, and JWM Farmouts.

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

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

14 unchanged sentences

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, ten wells to be drilled in the second program year, and, beginning with the third program year, fifteen wells per year beginning thereafter.

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 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,

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.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the Partnership will obtain a majority of the original working interest in such well group.

As of December 31, 2022, a total of eighteen wells have been spud in the contract area subject to the Pivotal Farmout.

Aethon within the contract area subject to the agreement.

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.

Impairment of Oil and Natural Gas Properties

2 unchanged sentences

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.

There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the same time demand weakened due to the impact of the COVID-19 pandemic.

The Partnership determined these events and

circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired.

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

The Partnership recognized impairment of oil and natural gas properties of $ 51.0 million for the year ended December 31, 2020.

See Note 6 - Fair Value Measurements for further discussion.

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

NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

11 unchanged sentences

Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of December 31, 2023 and 2022.

See Note 6 – Fair Value Measurements for further discussion.

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

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets.

43 unchanged sentences

The Partnership had the following open derivative contracts for oil as of December 31, 2023:

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

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

Period and Type of Contract Low High

6 unchanged sentences

The Partnership had the following open derivative contracts for natural gas as of December 31, 2023:

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

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

Period and Type of Contract Low High

4 unchanged sentences

Fourth quarter 10,120 3.57 3.48 3.76

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 210 $ 70.50 $ 70.16 $ 70.75

Second quarter 210 70.50 70.16 70.75

Third quarter 210 70.50 70.16 70.75

Fourth quarter 210 70.50 70.16 70.75

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, 2023:

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

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

Period and Type of Contract Low High

4 unchanged sentences

Fourth quarter 460 3.00 3.00 3.00

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 estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data.

See Note 5 – Commodity Derivative Financial Instruments for further discussion.

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

The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis:

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

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

This evaluation is performed on a depletable unit basis.

When assessing producing properties for impairment, the Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability.

The Partnership estimated the fair value of the impaired properties using published forward commodity price curves as of the measurement date of March 31, 2020, considering locational and quality differentials based on a review of historical realizations, and using an annual discount rate of 8 %.

Fair Value Measurements Using

Level 1 Level 2 Level 3 Impairment

(in thousands)

Year Ended December 31, 2022

Impaired oil and natural gas properties $ — $ — $ — $ —

Year Ended December 31, 2021

Impaired oil and natural gas properties $ — $ — $ — $ —

Year Ended December 31, 2020

Impaired oil and natural gas properties $ — $ — $ 2,044 $ 51,031

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 Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data.

These estimates involve uncertainty and cannot be determined with precision.

Changes to these estimates, particularly related to economic reserves, future commodity prices, and timing of future production could result in additional impairment charges in the future.

There were no significant changes in valuation techniques or related inputs for the years ended December 31, 2023 and 2022.

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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.

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 amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices.

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

redeterminations.

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.

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

The April and October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $ 400.0 million.

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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 next semi-annual redetermination is scheduled for April 2024.

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 ½ of 1.00 %, 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, 2021 the applicable margin for the alternative base rate ranged from 1.50 % and 2.50 % and the applicable margin for LIBOR ranged from 2.50 % and 3.50 % depending on the borrowings outstanding in relation to the borrowing base.

As of December 31, 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 weighted-average interest rate of the Credit Facility was 6.92 % and 2.61 % as of December 31, 2022 and 2021, respectively.

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 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 7.36 % during the twelve months ended December 31, 2023 and the weighted-average interest rate was 6.92 % as of December 31, 2022.

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.

In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375 % if the borrowing base utilization percentage is less than 50 %, or 0.500 % per annum if the borrowing base utilization percentage is equal to or greater than 50 %.

The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

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As of December 31, 2023, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $ 10.0 million and $ 89.0 million at December 31, 2022 and 2021, respectively.

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.

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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.

The Series B cumulative convertible preferred units are entitled to quarterly distributions in an amount equal to 7.0 % of the face amount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as

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

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

commencing on November 28, 2023 and readjusting every two years thereafter (each, a “Readjustment Date”), the rate will equal 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;

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;

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 Series B cumulative convertible preferred units had a carrying value of $ 298.4 million, including accrued distributions of $ 5.3 million, as of December 31, 2022 and 2021.

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.

The Partnership has the option to redeem the Series B cumulative convertible preferred units for a 90 day period beginning on November 28, 2023 at a redemption price of $ 21.41 per Series B cumulative convertible preferred unit.

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 Series B cumulative convertible preferred units had a carrying value of $ 299.1 million, including accrued distributions of $ 6.0 million, as of December 31, 2023 and a carrying value of $ 298.4 million, including accrued distributions of $ 5.3 million as of December 31, 2022.

NOTE 13 — EARNINGS PER UNIT

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$ 400,773 $ 455,480 $ 160,987

Weighted average common units outstanding:

Weighted average common units outstanding (basic) 209,382 208,181 206,705

Numerator for basic EPU - Net income (loss) attributable to common unitholders $ 400,773 $ 455,480 $ 160,987

Effect of dilutive securities 21,776 21,000 —

Weighted average common units outstanding (diluted) 224,446 208,290 206,819

Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities $ 422,549 $ 476,480 $ 160,987

Denominator for basic EPU - weighted average common units outstanding (basic) 209,970 209,382 208,181

Effect of dilutive securities

15,135 15,064 109

Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities 225,105 224,446 208,290

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

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Per common unit (diluted) 1.88 2.12 0.77

2.12 0.77 0.49

1 For the year ended December 31, 2022 diluted net income (loss) attributable to common units included distributions on Series B cumulative convertible preferred units of $ 21 million.

The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:

4 unchanged sentences

Series B cumulative convertible preferred units on an as-converted basis — — 14,968

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — COMMON UNITS

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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 % per annum, subject to certain adjustments;

• 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, adjusted to 9.8 % effective November 28, 2023 and subject to readjustment every two years thereafter;

• second , to the holders of common units.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

2 unchanged sentences

Distributions declared and paid per common unit $ 1.90 $ 1.54 $ 0.85

Common Unit Repurchase Program

On October 30, 2023, the Board authorized a $ 150.0 million unit repurchase program, terminating its existing $ 75.0 million program authorized in 2018.

The unit repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market condition, applicable legal requirements, available liquidity, and other appropriate factors.

The Partnership made no repurchases under this program for the year ended December 31, 2023.

The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility.

Any repurchased units are canceled.

NOTE 15 — SUBSEQUENT EVENTS

Leadership Change

On January 18, 2023, the Partnership announced that Jeff Wood, the President, Chief Financial Officer, and Treasurer of the Partnership's general partner, will leave the Partnership effective February 28, 2023.

Wood's departure, Evan Kiefer, who currently serves as Vice President, Finance and Investor Relations, will assume the role of Interim Chief Financial Officer and Treasurer.

The Partnership does not expect Mr.

Wood's departure to have a material impact on its operations.

On February 1, 2023, the Board approved a distribution for the period from October 1, 2022 to December 31, 2022 of $ 0.475 per common unit.

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.

Distributions will be paid on February 23, 2024 to unitholders of record at the close of business on February 16, 2024.

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Total $ 19,206 $ 11,442 $ 25,537

1 See Note 4 – Oil and Natural Gas Properties for further discussion.

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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4,817 38,537 11,240

Purchases of minerals in place 2

Sales of minerals in place 4

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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 3

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1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

The most notable revisions in 2020 are related to a reduction of royalty on certain Haynesville/Bossier wells in order to incentivize the operator to complete and turn the wells to sales.

The most notable revisions in 2022 and 2021 are related to changes in commodity pricing.

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.

3 Includes extensions and additions related to drilling activities within multiple basins.

3 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 2020 these were primarily in the Permian Basin and in 2021 these were primarily in the Anadarko Basin.

In 2021 these were primarily in the Anadarko Basin.

BLACK STONE MINERALS, L.P.

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however, these amounts are not material.

See Note 2 – Summary of Significant Accounting Policies for further discussion.

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

Year Ended December 31,

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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