What changed in this filing

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Item 9A. Controls and Procedures

2023-02-23 compared with 2022-02-22 · 201 added, 235 removed, 1018 unchanged (30% of the section changed)

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Evaluation of Disclosure Controls and Procedures

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.

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.

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, 2022 to provide such reasonable assurance.

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OTHER INFORMATION

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

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PRINCIPAL ACCOUNTING FEES AND SERVICES

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

Information required by this item is incorporated by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2022.

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as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of April 30, 2021.

Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein by reference to Exhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No.

333-202875)).

Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein by reference to Exhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No.

333-202875)).

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

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.

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333-202875)).

Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) 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 Current Report on Form 8-K filed on February 19, 2016 (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

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

Long-Term Incentive Plan

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.

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.

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.

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

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

Description of the Matter At December 31, 2021, the net book value of the Partnership’s oil and natural gas properties was $1,132 million, and depreciation, depletion and amortization (“DD&A”) expense was $61 million for the year then ended.

Description of

At December 31, 2022, the net book value of the Partnership’s oil and natural gas properties was $1,087 million, and depreciation, depletion and amortization (“DD&A”) expense related to the Partnership’s oil and natural gas properties was $47 million for the year then ended.

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

DD&A is recorded based on the units-of-production method.

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.

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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.

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

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

Because of the complexity involved in estimating oil and natural gas reserves, management used independent petroleum engineers to prepare the oil and natural gas reserve estimates as of December 31, 2021.

Auditing the Partnership’s DD&A 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.

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.

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, 2022.

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.

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the independent petroleum engineers used to prepare the oil and natural gas reserve 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 agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence.

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

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.

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.

Revenues from Contracts with Customers Accrual

Description of the Matter At December 31, 2021, the Partnership had $93 million in accrued revenues from contracts with customers.

Description of

At December 31, 2022, the Partnership had $129 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.

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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 accrual is challenging because the Partnership’s mineral and royalty interests include ownership in a significant amount of producing wells.

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 agreeing them to source documentation and evaluating corroborative and contrary evidence.

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

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

/s/ Ernst & Young LLP

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

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 160,987 $ 100,819 $ 193,368

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 455,480 $ 160,987 $ 100,819

ALLOCATION OF NET INCOME (LOSS):

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Common units 455,480 160,987 100,819

Subordinated units — — 23,993

$ 455,480 $ 160,987 $ 100,819

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

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

Per common unit (basic) $ 2.18 $ 0.77 $ 0.49

Weighted average common units outstanding (basic) 208,181 206,705 168,230

Per subordinated unit (basic) $ — $ — $ 0.64

Weighted average subordinated units outstanding (basic) — — 37,740

Per common unit (diluted) 1

$ 2.12 $ 0.77 $ 0.49

WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:

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

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

Per subordinated unit (diluted) $ — $ — $ 0.64

Weighted average subordinated units outstanding (diluted) — — 37,740

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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CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)

CONSOLIDATED STATEMENTS OF EQUITY (in thousands)

BALANCE AT DECEMBER 31, 2019 205,960 $ 798,443 $ 798,443

Conversion of subordinated units 96,329 ( 96,329 ) 142,149 ( 142,149 ) —

Repurchases of common and subordinated units ( 966 ) — ( 16,287 ) — ( 16,287 )

Issuance of common units, net of offering costs — — ( 43 ) — ( 43 )

Issuance of common units for property acquisitions 57 — 943 — 943

Conversion of Series A redeemable preferred units

Repurchases of common units ( 503 ) ( 5,035 ) ( 5,035 )

Restricted units granted, net of forfeitures 1,292 — —

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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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CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from issuance of common units, net of offering costs — — ( 43 )

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

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

Distributions equivalents paid — — ( 2,981 )

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

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND BASIS OF PRESENTATION

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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 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.

As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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

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

BLACK STONE MINERALS, L.P.

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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.

As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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.

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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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

The Partnership believes the credit quality of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

its customer base is high and has not experienced significant write-offs in its accounts receivable balances.

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.

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

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

As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties.

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

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

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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

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properties, as well as geographic and geologic data.

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.

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Amortization expense for debt issuance costs was $ 2.0 million, $ 1.6 million, and $ 1.0 million for the years ended December 31, 2022, 2021, and 2020, respectively, and is included in interest expense in the consolidated statements of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

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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.

Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term

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liabilities in the consolidated balance sheets.

As of December 31, 2021, none of the Partnership’s leases were classified as financing leases.

Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets.

As of December 31, 2022 and 2021, none of the Partnership’s leases were classified as financing leases.

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.

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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 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

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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.

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Lease bonus and other income

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See Note 6 – Fair Value Measurements for further discussion.

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Incentive Compensation

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Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans.

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

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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NOTE 4 — OIL AND NATURAL GAS PROPERTIES

The Partnership had no material divestiture activity during 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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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 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.

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.

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proceeds of approximately $ 54.5 million.

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

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.

2021 Acquisitions

The Partnership had no material acquisition activity during 2022 and 2020.

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.

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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.

2020 Acquisitions

The Partnership had no acquisition activity during the year ended December 31, 2020.

2019 Acquisitions

During the year ended December 31, 2019, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $ 44.0 million.

Acquisitions that were considered business combinations were primarily located in the Permian Basin.

These acquisitions were funded with borrowings under the Partnership's Credit Facility (as defined in Note 8 - Credit Facility) and funds from operating activities.

Acquisition related costs of $ 0.1 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2019.

The following table summarizes these acquisitions:

Assets Acquired Consideration Paid

Proved Unproved Net Working Capital Total Fair Value Cash

(in thousands)

February $ 173 $ 8,437 $ 1 $ 8,611 $ 8,611

March 24 — — 24 24

June 527 3,268 — 3,795 3,795

Total fair value $ 724 $ 11,705 $ 1 $ 12,430 $ 12,430

In addition, during 2019, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for an aggregate of $ 31.6 million.

These acquisitions were primarily located in East Texas and the Permian Basin.

The cash portion of the consideration paid for these acquisitions of $ 30.7 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $ 0.9 million 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.

Farmout Agreements

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

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San Augustine Farmout

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

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.

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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, increasing to a minimum of twelve wells per year beginning with the fourth program year.

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").

These agreements each cover part of the Partnership's share of working interests under active development by Aethon in San Augustine County, Texas.

The Canaan and Azul Farmouts continue until May and December 2031, respectively, unless earlier terminated in accordance with the terms of the agreements.

Canaan and Azul 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 will earn 80 % of the Partnership's working interest in the partitioned acreage from XTO (up to a maximum of 40 % on an 8/8ths basis) and 50 % of the Partnership's working interest in other areas (up to a maximum of 12.5 % on an 8/8ths basis).

Azul will earn the remaining 20 % of the Partnership's working interest in the partitioned acreage from XTO (up to a maximum of 10 % on an 8/8ths basis) and the remaining 50 % of the Partnership's working interest in other areas (up to a maximum of 12.5 % on an 8/8ths basis).

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

The Partnership will receive an ORRI before payout and an increased ORRI after payout on all wells drilled under the Azul and Canaan Farmouts.

As of December 31, 2021, three wells have been spud in the contract area subject to the Azul and Canaan Farmouts.

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

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Augustine County, Texas and continue for a ten 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, 2022, ten 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

Augustine farmout agreements:

Brent Miller Area

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

Canaan 64.0 % 32.0 %

Azul 20.0 % 10.0 %

JWM 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 %

Azul 50.0 % 12.5 %

JWM 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, increasing to a minimum of fifteen wells per year beginning with the third program year.

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

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

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

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

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

As of December 31, 2021, a total of eight wells have been spud in the contract area subject to the Pivotal Farmout.

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,

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

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.

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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

12 unchanged sentences

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

As of December 31, 2021, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts.

As of December 31, 2022 and 2021, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts.

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

6 unchanged sentences

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

As of December 31, 2021, the Partnership had six counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Partnership's Credit Facility.

As of December 31, 2022, the Partnership had seven counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.

BLACK STONE MINERALS, L.P.

55 unchanged sentences

Fourth quarter 8,280,000 5.15 3.28 6.59

First quarter 1,800,000 3.28 3.28 3.29

Second quarter 1,820,000 3.28 3.28 3.29

Third quarter 1,840,000 3.28 3.28 3.29

Fourth quarter 1,840,000 3.28 3.28 3.29

The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2021.

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

Period and Type of Contract Low High

Oil Swap Contracts:

First quarter 60,000 $ 83.36 $ 82.80 $ 83.91

Second quarter 180,000 83.36 82.80 83.91

Third quarter 180,000 83.36 82.80 83.91

Fourth quarter 180,000 83.36 82.80 83.91

First quarter 180,000 80.40 78.00 82.80

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, 2022:

6 unchanged sentences

Fourth quarter 3,680,000 3.67 3.57 3.76

First quarter 900,000 4.30 4.30 4.30

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 — FAIR VALUE MEASUREMENTS

18 unchanged sentences

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Fair Value Measurements Using Effect of Counterparty

Level 1 Level 2 Level 3 Netting Total

Fair Value Measurements Using Effect of

Level 1 Level 2 Level 3 Counterparty Netting Total

(in thousands)

9 unchanged sentences

Commodity derivative instruments — 53,545 — — 53,545

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

21 unchanged sentences

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2022 and 2021.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 — SIGNIFICANT CUSTOMERS

5 unchanged sentences

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

The Credit Facility has an aggregate maximum credit amount of $ 1.0 billion and terminates on November 1, 2024.

The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base.

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

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

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

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

The Partnership 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

1 unchanged sentence

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.

Effective May 1, 2020, the borrowing base was reduced from $ 650.0 million to $ 460.0 million.

Effective July 21, 2020, in connection with the closing of the Partnership's two asset sales in the Permian Basin, the borrowing base was further reduced to $ 430.0 million.

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base to $ 400.0 million.

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

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.

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 next semi-annual redetermination is scheduled for April 2023.

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50 %, or 1-month LIBOR plus 1.00 %) or LIBOR, in each case, plus the applicable margin.

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, 2021, the alternative base rate margin ranged from 1.50 % to 2.50 % and the LIBOR margin ranged from 2.50 % to 3.50 %.

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.

8 unchanged sentences

The unused portion of the available borrowings under the Credit Facility were $ 365.0 million and $ 311.0 million at December 31, 2022 and 2021, respectively.

On March 5, 2021, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks

to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S.

dollar settings and after June 30, 2023 for the

remaining U.S.

dollar settings.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary

during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”).

We currently do not expect the transition from LIBOR to have a material impact on us.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 — INCENTIVE COMPENSATION

2 unchanged sentences

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

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

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

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

The Partnership may also provide from time to time short-term and long-term cash incentive and retention awards annually for its directors, executive officers, and certain other employees.

Payments are disbursed as vesting is attained on a graded annual basis.

The last grant of such cash awards with graded vesting requirements was made in 2016 with vestings extending through December 31, 2019.

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

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Restricted Unit Awards

1 unchanged sentence

Award recipients have all the rights of a unitholder in the Partnership, including the right to receive distributions thereon, if and when made by the Partnership.

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

In conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the executive officers of the Partnership's general partner, certain other employees, and each of the non-employee directors of the Partnership’s general partner.

The grants included restricted common units subject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements that extended through March 15, 2019.

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

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

1 unchanged sentence

In January of each year, non-employee directors of the Partnership’s general partner receive compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about restricted units for the year ended December 31, 2022.

15 unchanged sentences

The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metrics are achieved.

Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate, are probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award.

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

Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate of performance metrics by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award.

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

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AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about performance units for the year ended December 31, 2022.

2 unchanged sentences

Unvested at December 31, 2021 1,062,487 $ 11.68

454,688 12.40

Vested ( 338,506 ) 17.09

5 unchanged sentences

The fair value of performance units vested for the years ended December 31, 2022, 2021 and 2020 was $ 3.9 million, $ 2.8 million and $ 5.5 million, respectively.

Aspirational Performance Unit Awards

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

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

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

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

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

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

The following table summarizes information about the aspirational performance units for the year ended December 31, 2022.

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

Fair Value per Unit

Unvested at December 31, 2021 — $ —

Granted 1,476,943 11.58

Forfeited ( 64,935 ) 11.55

Unvested at December 31, 2022 1,412,008 11.58

Total compensation expense to be recognized over the life of the Aspirational Awards consists of $ 5.2 million for the performance cash awards and $ 16.4 million for the performance equity awards.

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

As of December 31, 2022, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Incentive Compensation Expense

The table below summarizes incentive compensation expense recorded in General and administrative expenses in the consolidated statements of operations for the years ended December 31, 2022, 2021, and 2020.

3 unchanged sentences

Cash — short and long-term incentive plan $ 7,095 $ 6,824 $ 2,962

Equity-based compensation — restricted common and subordinated units 4,146 4,688 10,751

Equity-based compensation — restricted common units 4,089 4,146 4,688

Equity-based compensation — restricted performance units 11,174 6,320 ( 2,417 )

18 unchanged sentences

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 $ 20.3926 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 % of the face amount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows:

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;

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

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

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The Partnership cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions.

3 unchanged sentences

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.

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.

NOTE 13 — EARNINGS PER UNIT

3 unchanged sentences

For the periods presented, the amount of earnings allocated to these participating units was not material.

Net income (loss) attributable to the Partnership is allocated to the Partnership's general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.

Net income (loss) attributable to the Partnership is allocated to the Partnership's general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.

The Partnership assesses the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU.

10 unchanged sentences

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

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 160,987 $ 100,819 $ 193,368

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 455,480 $ 160,987 $ 100,819

ALLOCATION OF NET INCOME (LOSS):

1 unchanged sentence

Common units 455,480 160,987 100,819

Subordinated units — — 23,993

$ 455,480 $ 160,987 $ 100,819

3 unchanged sentences

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

Weighted average subordinated units outstanding:

Weighted average subordinated units outstanding (basic) — — 37,740

Effect of dilutive securities — — —

Weighted average subordinated units outstanding (diluted) — — 37,740

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

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

Per common unit (basic) $ 2.18 $ 0.77 $ 0.49

Per subordinated unit (basic) — — 0.64

Per common unit (diluted) 1

2.12 0.77 0.49

Per subordinated unit (diluted) 2

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 14,968

14,968 14,968 14,968

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — COMMON AND SUBORDINATED UNITS

Common and Subordinated Units

The common units and subordinated units represent limited partner interests in the Partnership.

NOTE 14 — COMMON UNITS

The common units represent limited partner interests in the Partnership.

The holders of common units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units under the partnership agreement.

The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in Black Stone Minerals Company, L.P.

prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control may not vote on any matter.

The holders of common units are and, prior to the end of the subordination period (as defined in the Partnership agreement), the subordinated units were, entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units, respectively, under the partnership agreement.

The subordination period under the partnership agreement ended on the first business day after the Partnership earned and paid an aggregate amount of at least $ 1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there were no outstanding arrearages on the common units.

This test was met upon the payment of the distribution for the first quarter of 2019.

Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and the priority right of the common unitholders ceased to exist.

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

1 unchanged sentence

• second , to the holders of common units.

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

Year Ended December 31,

2021 2020 2019

DISTRIBUTIONS DECLARED AND PAID:

Per common unit $ 0.85 $ 0.68 $ 1.48

Per subordinated unit — — 0.74

Common Unit Repurchase Program

On November 5, 2018, the Board authorized the repurchase of up to $ 75.0 million in common units.

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

The Partnership made no repurchases under this program for the year ended December 31, 2021.

As of December 31, 2021, the Partnership has repurchased $ 4.2 million in common units under the repurchase program since inception.

The repurchase program is funded from the Partnership's cash on hand or availability under the Credit Facility.

Any repurchased units are canceled.

At-The-Market Offering Program

On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”).

Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering amount of up to $ 100,000,000 .

Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale.

Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.

The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility.

The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.

For the years ended December 31, 2021, 2020, and 2019, the Partnership sold no common units under the ATM Program.

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

Year Ended December 31,

2022 2021 2020

Distributions declared and paid per common unit $ 1.54 $ 0.85 $ 0.68

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.

2 unchanged sentences

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED

Geographic Area of Operation

25 unchanged sentences

Proved properties $ 2,094,563 $ 2,064,232

$ 2,064,232 $ 2,220,354

Unproved properties 909,344 937,395

2 unchanged sentences

Oil and natural gas properties, net $ 1,086,988 $ 1,131,896

1 Proved properties include capitalized costs related to farmout wells not yet assigned.

BLACK STONE MINERALS, L.P.

16 unchanged sentences

2,490 ( 22,337 ) ( 1,233 )

Purchases of minerals in place 2

Sales of minerals in place 4

( 1,262 ) ( 3,132 ) ( 1,784 )

Extensions, discoveries and other additions 3

5 unchanged sentences

4,817 38,537 11,240

Purchases of minerals in place 2

Sales of minerals in place 4

7 unchanged sentences

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

12 unchanged sentences

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 2019 are related to well performance in certain Haynesville/ Bossier wells.

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 2021 are related to changes in commodity pricing.

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

2 Includes the acquisition of mineral and royalty reserves.

In 2020 these were primarily in East Texas and the Permian Basin and in 2021 these were primarily in the Permian Basin.

In 2021 these were primarily in the Permian Basin.

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

1 unchanged sentence

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

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AND SUBSIDIARIES

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED

Standardized Measure of Discounted Future Net Cash Flows

32 unchanged sentences

Sales of reserves in place — ( 1,037 ) ( 26,795 )

( 1,037 ) ( 26,795 ) ( 3,323 )

Changes in timing and other ( 28,704 ) ( 49,474 ) 19,807

6 unchanged sentences

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