What changed in this filing

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Item 9A. Controls and Procedures

2022-02-22 compared with 2021-02-23 · 174 added, 217 removed, 1079 unchanged (27% of the section changed)

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Evaluation of Disclosure Controls and Procedures

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.

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.

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3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No.

Amendment No.

4 to First Amended and Restated Agreement of Limited Partnership of the Black Stone Minerals, L.P., dated as of April 22, 2020 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on April 24, 2020 (SEC File No.

Description of Securities (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 25, 2020 (SEC File No.

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Fourth Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of November 3, 2020.

Fifth Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P.

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

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.

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BLACK STONE MINERALS, L.P.

Reports of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm (PCAOB ID:

Consolidated Balance Sheets

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

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

Description of the Matter At December 31, 2020, the net book value of the Partnership’s oil and natural gas properties was $1,170 million, and depreciation, depletion and amortization (“DD&A”) expense related to the Partnership's producing oil and natural gas properties was $81 million and impairment of oil and natural gas properties was $51 million for the year then ended.

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.

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

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

When events or changes in circumstances indicate that the carrying amount of oil and natural gas properties may not be recoverable, the Partnership compares the undiscounted projected future cash flows to the unamortized carrying amount on a depletable unit basis.

If the carrying amount exceeds its projected undiscounted future cash flows, the carrying amount is written down to its fair value.

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.

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.

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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 and impairment calculations 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 and impairment, 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 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.

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 and impairment calculations, including comparing the proved oil and natural gas reserve amounts used in the calculations to the Partnership’s reserve report.

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.

Revenues from Contracts with Customers Accrual

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NET INCOME (LOSS) 181,987 121,819 214,368

Net (income) loss attributable to noncontrolling interests — — ( 24 )

Distributions on Series A redeemable preferred units — — ( 25 )

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

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(in thousands)

Noncontrolling

BALANCE AT DECEMBER 31, 2018 108,363 96,329 $ 714,823 $ 189,440 $ 904,263

Conversion of Series A redeemable preferred units 736 964 10,498 13,750 — 24,248

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

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

Purchase of noncontrolling interests — — ( 1,026 ) — ( 680 ) ( 1,706 )

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

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Charges to partners' equity for accrued distribution equivalent rights — — ( 2,852 ) — ( 2,852 )

Distributions on Series A redeemable preferred units — — ( 13 ) ( 12 ) — ( 25 )

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

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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

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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Exploratory dry hole expense 1,048 — 3

Deferred rent — — 1,283

(Gain) loss on sale of assets, net ( 2,850 ) ( 24,045 ) —

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Distributions to common and subordinated unitholders ( 176,924 ) ( 140,343 ) ( 304,439 )

Distributions to Series A redeemable preferred unitholders — — ( 690 )

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

Distributions to noncontrolling interests — — ( 211 )

Distributions equivalents paid — — ( 2,981 )

Redemption of Series A redeemable preferred units — — ( 2,115 )

Repurchases of common and subordinated units ( 1,957 ) ( 5,035 ) ( 16,929 )

Purchase of noncontrolling interests — — ( 1,706 )

Borrowings under credit facility 212,000 160,000 334,500

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND BASIS OF PRESENTATION

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards.

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.

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’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties.

The Partnership attempts to limit the amount of credit exposure to any one company through

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

procedures that include credit approvals, credit limits and terms, and prepayments.

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

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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Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC").

The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which the Partnership also refers to as a depletable unit.

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

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

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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 as of March 31, 2020.

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

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.

There was no impairment of proved oil and natural gas properties for the years ended December 31, 2021 and 2019.

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

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

properties, as well as geographic and geologic data.

There was no impairment of unproved properties for the years ended December 31, 2021, 2020, and 2019.

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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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

liabilities in the consolidated balance sheets.

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

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.

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.

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ASC 606, Revenue from Contracts with Customers , requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified.

The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.

Oil and natural gas sales

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Oil and natural gas sales

The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

unsatisfied performance obligation.

Lease bonus and other income

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

Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP.

Prior-period performance obligations

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

On January 1, 2020, the Partnership adopted Accounting Standards Update ("ASU") 2018-13, Fair Value Measurements (Topic 820) , which removed, modified, and added certain required disclosures on fair value measurements.

The adoption of this update had no impact on the Partnership's financial position, results of operations, or liquidity

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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

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

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

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Non-current asset retirement obligations $ 12,561 $ 17,377

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4 — OIL AND NATURAL GAS PROPERTIES

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

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

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

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

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

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.

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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.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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2021 Acquisitions

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

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

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

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

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

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

2020 Acquisitions

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

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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.

2018 Acquisitions

During the year ended December 31, 2018, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $ 149.9 million.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Acquisition related costs of $ 0.2 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, 2018.

The following table summarizes these acquisitions:

Assets Acquired Consideration Paid

Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued

(in thousands)

March $ 984 $ 21,452 $ 133 $ 22,569 $ 22,569 $ —

June 883 13,688 8 14,579 14,579 —

July 4,349 7,944 215 12,508 3,764 8,744

August 5,000 34,673 74 39,747 26,461 13,286

September 1,176 — — 1,176 1,176 —

November 1,166 — — 1,166 1,166 —

Total fair value $ 13,558 $ 77,757 $ 430 $ 91,745 $ 69,715 $ 22,030

In addition, during 2018, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for an aggregate of $ 58.2 million.

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

The cash portion of the consideration paid for these acquisitions of $ 57.6 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $ 0.6 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.

During 2018, the Partnership acquired the remaining noncontrolling interest in certain subsidiaries for $ 1.7 million and merged the subsidiaries into its existing structure.

This acquisition was funded with borrowings under the Partnership's Credit Facility and funds from operating activities.

Farmout Agreements

In 2017, the Partnership entered into two farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions.

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

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

Canaan Farmout

In February 2017, the Partnership entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc.

("XTO"), a subsidiary of Exxon Mobil Corporation.

The Partnership has an approximate 50 % working interest in the acreage and is the largest mineral owner.

During the first three phases of the farmout agreement, Canaan commits on a phase-by-phase basis and funds 80 % of the Partnership's drilling and completion costs and is assigned 80 % of the Partnership's working interests in such wells ( 40 % working interest on an 8/8ths basis) as the wells are drilled.

After the third phase, Canaan can earn 40 % of the Partnership’s working interest ( 20 % working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40 % of the Partnership's costs for those wells on a well-by-well basis.

The Partnership receives an ORRI before payout and an increased ORRI after payout on all wells drilled under the agreement.

Canaan has participated in a total of 37 wells under the farmout agreement through December 31, 2020, covering two election phases.

In 2019, XTO suspended its development activities in the area due to low natural gas prices.

Canaan has the right to elect to continue its participation in a third phase covering up to 20 future wells drilled under the farmout agreement should XTO resume drilling activity.

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.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pivotal Farmout

In November 2017, the Partnership entered into a farmout agreement (the "First Pivotal Farmout") with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC.

The farmout agreement covers substantially all of the Partnership's remaining working interests in wells operated by XTO Energy and BPX Energy in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage (after giving effect to the Canaan Farmout), until November 2025.

Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout 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, 2020, a total of 68 wells have been spud in the contract area subject to the First Pivotal Farmout.

The Partnership's development agreement with BPX Energy terminated in 2019 with respect to the majority of the Partnership's acreage covered by the agreement.

As such, Pivotal retains minimal rights or obligations related to the farmout for that area that remains subject to the First Pivotal Farmout.

In the second quarter of 2020, the Partnership entered into a development agreement with Aethon Energy ("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 our 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 15 wells per year beginning with the third program year.

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

The Second Pivotal Farmout supersedes and replaces the First Pivotal Farmout with respect to the area covered by the Aethon development agreement.

The Second 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 with 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 in accordance with the development 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 Second Pivotal Farmout.

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.

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

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

The 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, increasing to 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.

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 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.

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, 2020, a total of 2 wells have been spud in the contract area subject to the Second Pivotal Farmout.

From the inception of the farmout agreements through December 31, 2020, the Partnership has received $ 90.2 million and $ 119.2 million from Canaan and Pivotal, respectively, under the agreements.

When such reimbursements are received prior to assigning the wells to Canaan and Pivotal, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities.

When working interests in farmout wells are assigned to Canaan and Pivotal, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs.

As of December 31, 2020 and 2019, $ 0.1 million and $ 1.7 million, respectively, were included in the Other long-term liabilities line item of the consolidated balance sheets for reimbursements received associated with farmed-out working interests not yet assigned to Canaan and Pivotal.

XTO Completions Agreement

In June 2020, the Partnership entered into a new incentive agreement with XTO with respect to certain drilled but uncompleted wells ("DUCs") in the Shelby Trough.

The agreement allows for royalty relief on 13 existing DUCs if XTO completes and turns the wells to sales by March 31, 2021.

As of January 18, 2021, XTO has turned all 13 DUCs to sales.

As of December 31, 2021, a total of eight 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.

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.

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

No impairment of oil and natural gas properties was recognized during 2019.

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, 2021 and 2019.

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.

3 unchanged sentences

From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements.

The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

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

As of December 31, 2020, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts and costless collar contracts.

A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date.

A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date.

The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

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

As of December 31, 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, 2020, the Partnership had eight 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, 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.

BLACK STONE MINERALS, L.P.

47 unchanged sentences

Fourth quarter 480,000 60.14 55.29 65.50

Volume (Bbl) Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl)

Period and Type of Contract

Oil Collar Contracts:

Fourth quarter 70,000 56.43 67.14

The Partnership had the following open derivative contracts for natural gas as of December 31, 2021:

6 unchanged sentences

Fourth quarter 8,080,000 2.99 2.80 3.15

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, 2021.

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

Period and Type of Contract Low High

Natural Gas Swap Contracts:

First quarter 310,000 $ 4.30 $ 4.30 $ 4.30

Second quarter 910,000 4.30 4.30 4.30

Third quarter 920,000 4.30 4.30 4.30

Fourth quarter 920,000 4.30 4.30 4.30

First quarter 900,000 4.30 4.30 4.30

NOTE 6 — FAIR VALUE MEASUREMENTS

9 unchanged sentences

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

The Partnership’s assessment of the significance of a particular input to the fair value

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

measurement in its entirety requires judgment and considers factors specific to the asset or liability.

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

There were no transfers into, or out of, the three levels of the fair value hierarchy for the years ended December 31, 2021 and 2020.

6 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:

21 unchanged sentences

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 %.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements Using

12 unchanged sentences

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2021 and 2019.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 — SIGNIFICANT CUSTOMERS

10 unchanged sentences

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.

Effective October 23, 2019, the borrowing base redetermination reduced the borrowing base to $ 650.0 million.

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

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

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

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 most recent borrowing base redetermination reduced the borrowing base to $ 400.0 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 next semi-annual redetermination is scheduled for April 2022.

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership 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.

Prior to October 31, 2018, the applicable margin ranged from 1.00 % to 2.00 % in the case of the alternative base rate and from 2.00 % to 3.00 % in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base.

Effective October 31, 2018, the applicable margin for the alternative base rate was reduced to between 0.75 % and 1.75 % and the applicable margin for LIBOR was reduced to between 1.75 % and 2.75 %.

Effective November 3, 2020, the LIBOR margin was increased to between 2.00 % and 3.00 % and the alternative base rate margin was increased to between 1.00 % and 2.00 %.

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.

As of December 31, 2020 the applicable margin for the alternative base rate ranged from 1.00 % and 2.00 % and the applicable margin for LIBOR ranged from 2.00 % and 3.00 % 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 %.

The weighted-average interest rate of the Credit Facility was 2.61 % and 2.40 % as of December 31, 2021 and 2020, respectively.

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

percentage is less than 50 %, or 0.500 % per annum if the borrowing base utilization percentage is equal to or greater than 50 %.

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.

1 unchanged sentence

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

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

As of December 31, 2021, the Partnership was in compliance with all financial covenants in the Credit Facility.

1 unchanged sentence

The unused portion of the available borrowings under the Credit Facility were $ 311.0 million and $ 279.0 million at December 31, 2021 and 2020, 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

43 unchanged sentences

Unvested at December 31, 2020 882,310 $ 14.96

340,036 10.95

Vested ( 300,868 ) 17.95

32 unchanged sentences

NOTE 12 — PREFERRED UNITS

Series A Redeemable Preferred Units

As of December 31, 2020 and 2019, there were no Series A redeemable preferred units outstanding.

The Series A redeemable preferred units were entitled to an annual distribution of 10 % of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears.

The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders.

The Series A redeemable preferred units had an adjusted conversion price of $ 14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit.

The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions.

Series B Cumulative Convertible Preferred Units

On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $ 20.3926 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

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter.

For the year ended December 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $ 2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $ 24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017.

Series B Cumulative Convertible Preferred Units

The Series B cumulative convertible preferred units are entitled to an annual distribution of 7 %, payable on a quarterly basis in arrears.

For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash.

Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash.

The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $ 20.3926 .

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

The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $ 20.3926 , adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date.

8 unchanged sentences

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.

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

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

The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU.

The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period.

The following table sets forth the computation of basic and diluted earnings per unit:

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the computation of basic and diluted earnings per unit:

For the Year Ended December 31,

2 unchanged sentences

NET INCOME (LOSS) $ 181,987 $ 121,819 $ 214,368

Net (income) loss attributable to noncontrolling interests — — ( 24 )

Distributions on Series A redeemable preferred units — — ( 25 )

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

19 unchanged sentences

Per subordinated unit (diluted) 2

1 For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $ 21.0 million.

2 For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $ 0.3 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:

3 unchanged sentences

Potentially dilutive securities (common units):

Series A redeemable preferred units on an as-converted basis — — 189

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

31 unchanged sentences

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”

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

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.

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.

2 unchanged sentences

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

For the year ended December 31, 2018, the Partnership sold 2,243,775 common units under the ATM Program for net proceeds of $ 40.5 million.

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

NOTE 15 — SUBSEQUENT EVENTS

On February 2, 2022, the Board approved a distribution for the period from October 1, 2021 to December 31, 2021 of $ 0.270 per common unit.

Distributions were paid on February 23, 2021 to unitholders of record at the close of business on February 16, 2021.

Distributions will be paid on February 23, 2022 to unitholders of record at the close of business on February 16, 2022.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Geographic Area of Operation

31 unchanged sentences

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED

Oil and Natural Gas Reserve Information

10 unchanged sentences

Net proved reserves at December 31, 2018

17,567 314,020 69,904

Revisions of previous estimates 1

5 unchanged sentences

Net proved reserves at December 31, 2019

17,050 308,958 68,543

Revisions of previous estimates 1

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

2 unchanged sentences

Net proved reserves at December 31, 2020

15,952 240,211 55,987

Revisions of previous estimates 1

4,817 38,537 11,240

Purchases of minerals in place 2

Sales of minerals in place 4

4 unchanged sentences

Net proved reserves at December 31, 2021

19,171 243,917 59,824

Net Proved Developed Reserves

7 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 2018 and 2019 are related to well performance in certain Haynesville/ Bossier wells.

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.

2 Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian Basin.

The most notable revisions in 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.

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

4 Includes divestitures of mineral and royalty reserves primarily in 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.

Standardized Measure of Discounted Future Net Cash Flows

16 unchanged sentences

Annual discount 10% for estimated timing

( 804,527 ) ( 309,675 ) ( 534,327 )

Total $ 972,122 $ 493,497 $ 847,894

17 unchanged sentences

Standardized measure, end of year $ 972,122 $ 493,497 $ 847,894

1 Due to minimal prior period divestiture activity, sales of reserves in place were previously classified as Changes in timing and other.

We changed the presentation of 2019 and 2018 to be consistent with our 2020 presentation.

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions.

2 unchanged sentences

Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.

Quarter Second

Quarter Third

Quarter Fourth

(In thousands, except for per unit data)

Total revenue $ 183,054 $ 38,529 $ 43,742 $ 77,426

Income (loss) from operations 80,509 ( 5,314 ) 25,228 31,686

Net income (loss) 76,112 ( 8,371 ) 23,733 30,345

Net income (loss) attributable to the general partner and common and subordinated units 70,862 ( 13,621 ) 18,483 25,095

Net income (loss) attributable to common and subordinated units per unit (basic) 1

Per common unit (basic) $ 0.34 $ ( 0.07 ) $ 0.09 $ 0.12

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

Net income (loss) attributable to common and subordinated units per unit (diluted) 1

Per common unit (diluted) $ 0.34 $ ( 0.07 ) $ 0.09 $ 0.12

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

Cash distributions declared and paid per limited partner unit

Per common unit $ 0.3000 $ 0.0800 $ 0.1500 $ 0.1500

Per subordinated unit — — — —

Total assets $ 1,522,567 $ 1,438,838 $ 1,260,016 $ 1,243,978

Long-term debt 388,000 323,000 147,000 121,000

Total mezzanine equity 298,361 298,361 298,361 298,361

Total revenue $ 83,806 $ 163,618 $ 137,369 $ 103,028

Income (loss) from operations 14,594 100,666 75,233 44,679

Net income (loss) 9,017 95,087 70,247 40,017

Net income (loss) attributable to the general partner and common and subordinated units 3,767 89,837 64,997 34,767

Net income (loss) attributable to common and subordinated units per unit (basic) 1

Per common unit (basic) $ 0.02 $ 0.45 $ 0.32 $ 0.17

Per subordinated unit (basic) $ 0.02 $ 0.39 $ — $ —

Net income (loss) attributable to common and subordinated units per unit (diluted) 1

Per common unit (diluted) $ 0.02 $ 0.44 $ 0.32 $ 0.17

Per subordinated unit (diluted) $ 0.02 $ 0.39 $ — $ —

Cash distributions declared and paid per limited partner unit

Per common unit $ 0.3700 $ 0.3700 $ 0.3700 $ 0.3700

Per subordinated unit 0.3700 0.3700 — —

Total assets $ 1,711,887 $ 1,724,555 $ 1,595,813 $ 1,545,208

Long-term debt 435,000 436,000 413,000 394,000

Total mezzanine equity 298,361 298,361 298,361 298,361

1 See Note 13 – Earnings Per Unit in the consolidated financial statements.

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