Black Stone Minerals, L.P. 10-K

ITEM 9A. CONTROLS AND PROCEDURES 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 66 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, 2021 to provide such reasonable assurance. Management’s Annual Report on Internal Control over Financial Reporting Our general partner’s management, including our general partner’s principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. There are inherent limitations in the effectiveness of internal control over financial reporting, including the possibility that misstatements may not be prevented or detected. Accordingly, even effective internal controls over financial reporting can provide only reasonable assurance with respect to financial statement preparation. Under the supervision and with the participation of our general partner's principal executive officer and principal financial officer, our general partner’s management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, our general partner’s management believes that our internal control over financial reporting was effective as of December 31, 2021. This Annual Report includes an attestation report of Ernst & Young LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2021, which is included in the Annual Report on page F-4. Changes in Internal Control over Financial Reporting There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None. 67 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE Information required by this item is incorporated by reference to the material appearing in our Proxy Statement for the 2022 Annual Meeting of Limited Partners (“2022 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2021. We have a Code of Business Conduct and Ethics that applies to our directors, officers, and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, and the other senior financial officers, each as required by SEC and NYSE rules. Each of the foregoing is available on our website at www.blackstoneminerals.com in the “Corporate Governance” section. We will provide copies, free of charge, of any of the foregoing upon receipt of a written request to Black Stone Minerals, L.P., 1001 Fannin Street, Suite 2020, Houston, Texas 77002, Attn: Investor Relations. We intend to disclose amendments to and waivers from our Financial Code of Ethics, if any, on our website, www.blackstoneminerals.com , promptly following the date of any such amendment or waiver. ITEM 11. EXECUTIVE COMPENSATION Information required by this item is incorporated by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2021. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS Information required by this item is incorporated by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2021. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE Information required by this item is incorporated by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2021. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Information required by this item is incorporated by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2021. 68 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) Financial Statements Our Consolidated Financial Statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying notes, please read “Index to Financial Statements” on page F-1 of this Annual Report. (a)(2) Financial Statement Schedules All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto. (a)(3) Exhibits The following documents are filed as a part of this Annual Report or incorporated by reference: Exhibit Number Description 3.1 Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 3.2 Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 3.3 First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)). 3.4 Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)). 3.5 Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)). 3.6 Amendment No. 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. 001-37362)). 3.7 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. 001-37362)). 4.1 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. 001-37362)). 4.2 Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Minerals Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)). 10.1 ^ Black Stone Minerals, L.P. Long-Term Incentive Plan, dated May 6, 2015, by Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)). 69 10.2 Fourth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A. DBA and Amegy Bank National Association, as Documentation Agent, and the lenders signatory thereto, dated as of November 1, 2017 (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 7, 2017 (SEC File No. 001-37362)). 10.3 First Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders dated as of February 7, 2018. 10.4 Second Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of October 31, 2018 (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 5, 2018 (SEC File No. 001-37362)). 10.5 Third Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of May 1, 2020. 10.6 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. 10.7 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. 10.8 ^ 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)). 10.9 ^ 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)). 10.10 ^ Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.11 ^ Form of Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.12 ^ Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.13 ^ 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. 001-37362). 10.14 ^ 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. 001-37362)). 10.15 Series B Preferred Unit Purchase Agreement, dated as of November 22, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)). 21.1 * List of Subsidiaries of Black Stone Minerals, L.P. 23.1 * Consent of Ernst & Young LLP 23.2 * Consent of Netherland, Sewell & Associates, Inc. 70 31.1 * Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 * Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 * Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.1 * Report of Netherland, Sewell & Associates, Inc. 101.INS* Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCH* Inline XBRL Taxonomy Schema Document. 101.CAL* Inline XBRL Taxonomy Calculation Linkbase Document. 101.DEF* Inline XBRL Taxonomy Definition Linkbase Document. 101.LAB* Inline XBRL Taxonomy Label Linkbase Document. 101.PRE* Inline XBRL Taxonomy Presentation Linkbase Document. 104* Cover Page Interactive Data File - the cover page iXBRL tags are embedded within the Inline XBRL document. * Filed herewith. ^ Management contract or compensatory plan or arrangement. 71 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BLACK STONE MINERALS, L.P. By: Black Stone Minerals GP, L.L.C., its general partner Date: February 22, 2022 By: /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. Chief Executive Officer and Chairman 72 Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date /s/ Thomas L. Carter, Jr. Chief Executive Officer and Chairman February 22, 2022 Thomas L. Carter, Jr. (Principal Executive Officer) /s/ Jeffrey P. Wood President and Chief Financial Officer February 22, 2022 Jeffrey P. Wood (Principal Financial Officer) /s/ Dawn K. Smajstrla Vice President and Chief Accounting Officer February 22, 2022 Dawn K. Smajstrla (Principal Accounting Officer) /s/ Carin M. Barth Director February 22, 2022 Carin M. Barth /s/ D. Mark DeWalch Director February 22, 2022 D. Mark DeWalch /s/ Jerry V. Kyle, Jr. Director February 22, 2022 Jerry V. Kyle, Jr. /s/ Michael C. Linn Director February 22, 2022 Michael C. Linn /s/ John H. Longmaid Director February 22, 2022 John H. Longmaid /s/ William N. Mathis Director February 22, 2022 William N. Mathis /s/ William E. Randall Director February 22, 2022 William E. Randall /s/ Alexander D. Stuart Director February 22, 2022 Alexander D. Stuart /s/ Allison K. Thacker Director February 22, 2022 Allison K. Thacker 73 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS BLACK STONE MINERALS, L.P. Report of Independent Registered Public Accounting Firm (PCAOB ID: 42 ) F- 2 Consolidated Balance Sheets F- 6 Consolidated Statements of Operations F- 7 Consolidated Statements of Equity F- 8 Consolidated Statements of Cash Flows F- 9 Notes to Consolidated Financial Statements F- 10 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Audit Committee of the Board of Directors and Unitholders of Black Stone Minerals, L.P. and subsidiaries Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Black Stone Minerals, L.P. and subsidiaries ("the Partnership”) as of December 31, 2021 and 2020, the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 22, 2022, expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 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. DD&A is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves, as estimated by independent petroleum engineers. Leasehold acquisition costs and costs to acquire proved properties are amortized on the basis of total proved reserves, also estimated by independent petroleum engineers. 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. 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. F-2 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. As discussed in Note 2, the Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the consolidated balance sheets. Auditing the Partnership’s revenues from contracts with customers accrual is complex and judgmental because it involves the evaluation of subjective management inputs and assumptions used in the calculation. Additionally, auditing the 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. 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. /s/ Ernst & Young LLP We have served as the Partnership’s auditor since 2016. Houston, Texas February 22, 2022 F-3 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Audit Committee of the Board of Directors and Unitholders of Black Stone Minerals, L.P. and subsidiaries Opinion on Internal Control Over Financial Reporting We have audited Black Stone Minerals, L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), ("the COSO criteria”). In our opinion, Black Stone Minerals, L.P. and subsidiaries ("the Partnership”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 22, 2022, expressed an unqualified opinion thereon. Basis for Opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Ernst & Young LLP Houston, Texas February 22, 2022 F-4 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands) As of December 31, 2021 2020 ASSETS CURRENT ASSETS Cash and cash equivalents $ 8,876 $ 1,796 Accounts receivable 97,142 61,908 Commodity derivative assets — 1,149 Prepaid expenses and other current assets 1,956 1,668 TOTAL CURRENT ASSETS 107,974 66,521 PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $ 937,395 and $ 937,464 at December 31, 2021 and 2020, respectively 3,001,627 3,157,818 Accumulated depreciation, depletion, amortization, and impairment ( 1,869,731 ) ( 1,987,332 ) Oil and natural gas properties, net 1,131,896 1,170,486 Other property and equipment, net of accumulated depreciation of $ 12,931 and $ 12,292 at December 31, 2021 and 2020, respectively 1,440 1,650 NET PROPERTY AND EQUIPMENT 1,133,336 1,172,136 DEFERRED CHARGES AND OTHER LONG-TERM ASSETS 6,611 5,321 TOTAL ASSETS $ 1,247,921 $ 1,243,978 LIABILITIES, MEZZANINE EQUITY, AND EQUITY CURRENT LIABILITIES Accounts payable $ 5,944 $ 3,407 Accrued liabilities 17,589 15,568 Commodity derivative liabilities 51,544 19,318 Other current liabilities 2,063 1,654 TOTAL CURRENT LIABILITIES 77,140 39,947 LONG-TERM LIABILITIES Credit facility 89,000 121,000 Accrued incentive compensation 838 766 Commodity derivative liabilities 2,001 1,848 Asset retirement obligations 12,561 17,377 Other long-term liabilities 2,752 4,073 TOTAL LIABILITIES 184,292 185,011 COMMITMENTS AND CONTINGENCIES (Note 11) MEZZANINE EQUITY Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2021 and 2020, respectively 298,361 298,361 EQUITY Partners' equity — general partner interest — — Partners' equity — common units, 208,666 and 206,749 units outstanding at December 31, 2021 and 2020, respectively 765,268 760,606 TOTAL EQUITY 765,268 760,606 TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY $ 1,247,921 $ 1,243,978 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-5 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit amounts) Year Ended December 31, 2021 2020 2019 REVENUE Oil and condensate sales $ 235,771 $ 148,631 $ 263,678 Natural gas and natural gas liquids sales 255,671 138,926 199,265 Lease bonus and other income 14,292 9,083 29,833 Revenue from contracts with customers 505,734 296,640 492,776 Gain (loss) on commodity derivative instruments ( 146,474 ) 46,111 ( 4,955 ) TOTAL REVENUE 359,260 342,751 487,821 OPERATING (INCOME) EXPENSE Lease operating expense 13,056 14,022 17,665 Production costs and ad valorem taxes 49,809 43,473 60,533 Exploration expense 1,082 29 397 Depreciation, depletion, and amortization 61,019 82,018 109,584 Impairment of oil and natural gas properties — 51,031 — General and administrative 48,746 42,983 63,353 Accretion of asset retirement obligations 1,073 1,131 1,117 (Gain) loss on sale of assets, net ( 2,850 ) ( 24,045 ) — TOTAL OPERATING EXPENSE 171,935 210,642 252,649 INCOME (LOSS) FROM OPERATIONS 187,325 132,109 235,172 OTHER INCOME (EXPENSE) Interest and investment income 1 35 159 Interest expense ( 5,638 ) ( 10,408 ) ( 21,435 ) Other income (expense) 299 83 472 TOTAL OTHER EXPENSE ( 5,338 ) ( 10,290 ) ( 20,804 ) NET INCOME (LOSS) 181,987 121,819 214,368 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 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 160,987 100,819 169,375 Subordinated units — — 23,993 $ 160,987 $ 100,819 $ 193,368 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.77 $ 0.49 $ 1.01 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) $ 0.77 $ 0.49 $ 1.01 Weighted average common units outstanding (diluted) 208,290 206,819 168,376 Per subordinated unit (diluted) $ — $ — $ 0.64 Weighted average subordinated units outstanding (diluted) — — 37,740 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-6 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (in thousands) Common units Subordinated units Partners' equity— common units Partners' equity— subordinated units Total equity BALANCE AT DECEMBER 31, 2018 108,363 96,329 $ 714,823 $ 189,440 $ 904,263 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 Restricted units granted, net of forfeitures 2,177 — — — — Equity-based compensation — — 23,490 — 23,490 Distributions — — ( 233,155 ) ( 71,284 ) ( 304,439 ) Charges to partners' equity for accrued distribution equivalent rights — — ( 2,852 ) — ( 2,852 ) Distributions on Series B cumulative convertible preferred units — — ( 21,000 ) — ( 21,000 ) Net income (loss) — — 190,375 23,993 214,368 BALANCE AT DECEMBER 31, 2019 205,960 — $ 798,443 $ — $ 798,443 Repurchases of common units ( 503 ) — ( 5,035 ) — ( 5,035 ) Restricted units granted, net of forfeitures 1,292 — — — — Equity-based compensation — — 7,118 — 7,118 Distributions — — ( 140,343 ) — ( 140,343 ) Charges to partners' equity for accrued distribution equivalent rights — — ( 396 ) — ( 396 ) Distributions on Series B cumulative convertible preferred units — — ( 21,000 ) — ( 21,000 ) Net income (loss) — — 121,819 — 121,819 BALANCE AT DECEMBER 31, 2020 206,749 — $ 760,606 $ — $ 760,606 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 — — — — Equity-based compensation — — 12,932 — 12,932 Distributions — — ( 176,924 ) — ( 176,924 ) Charges to partners' equity for accrued distribution equivalent rights — — ( 1,142 ) — ( 1,142 ) Distributions on Series B cumulative convertible preferred units — — ( 21,000 ) — ( 21,000 ) Net income (loss) — — 181,987 — 181,987 BALANCE AT DECEMBER 31, 2021 208,666 — 765,268 — 765,268 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-7 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31, 2021 2020 2019 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 181,987 $ 121,819 $ 214,368 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization 61,019 82,018 109,584 Impairment of oil and natural gas properties — 51,031 — Accretion of asset retirement obligations 1,073 1,131 1,117 Amortization of deferred charges 1,579 1,044 1,041 (Gain) loss on commodity derivative instruments 146,474 ( 46,111 ) 4,955 Net cash (paid) received on settlement of commodity derivative instruments ( 112,946 ) 81,349 27,862 Equity-based compensation 12,218 3,727 20,484 Exploratory dry hole expense 1,048 — 3 (Gain) loss on sale of assets, net ( 2,850 ) ( 24,045 ) — Changes in operating assets and liabilities: Accounts receivable ( 34,856 ) 16,494 35,044 Prepaid expenses and other current assets ( 289 ) ( 500 ) ( 167 ) Accounts payable, accrued liabilities, and other 2,652 ( 5,929 ) ( 1,191 ) Settlement of asset retirement obligations ( 229 ) ( 219 ) ( 380 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 256,880 281,809 412,720 CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of oil and natural gas properties ( 10,043 ) ( 28 ) ( 43,051 ) Additions to oil and natural gas properties ( 4,066 ) ( 3,969 ) ( 64,782 ) Additions to oil and natural gas properties leasehold costs ( 98 ) ( 798 ) ( 980 ) Purchases of other property and equipment ( 428 ) ( 21 ) ( 2,488 ) Proceeds from the sale of oil and natural gas properties 318 151,864 1,174 Proceeds from farmouts of oil and natural gas properties — 4,198 61,504 NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES ( 14,317 ) 151,246 ( 48,623 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of common units, net of offering costs — — ( 43 ) Distributions to common and subordinated unitholders ( 176,924 ) ( 140,343 ) ( 304,439 ) 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 ( 1,957 ) ( 5,035 ) ( 16,929 ) Borrowings under credit facility 212,000 160,000 334,500 Repayments under credit facility ( 244,000 ) ( 433,000 ) ( 350,500 ) Debt issuance costs and other ( 3,602 ) — — NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES ( 235,483 ) ( 439,378 ) ( 361,392 ) NET CHANGE IN CASH AND CASH EQUIVALENTS 7,080 ( 6,323 ) 2,705 Cash and cash equivalents — beginning of the year 1,796 8,119 5,414 Cash and cash equivalents — end of the year $ 8,876 $ 1,796 $ 8,119 SUPPLEMENTAL DISCLOSURE Interest paid $ 4,035 $ 9,449 $ 20,470 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-8 NOTE 1 — BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM." Basis of Presentation The accompanying audited consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20 % ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level. NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates. The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. 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. F-9 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES 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, 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. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates. Cash and Cash Equivalents The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Accounts Receivable The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry. The following table presents information about the Partnership's accounts receivable: December 31, 2021 2020 (in thousands) Accounts receivable: Revenues from contracts with customers $ 93,005 $ 58,181 Other 4,137 3,727 Total accounts receivable $ 97,142 $ 61,908 Commodity Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments. Concentration of Credit Risk Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. 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 procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of F-10 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 5 – Commodity Derivative Financial Instruments for further discussion. Oil and Natural Gas Properties The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. The costs of unproved leasehold 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. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. 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 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. DD&A of producing 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 while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved 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. DD&A expense related to the Partnership’s producing oil and natural gas properties was $ 60.4 million, $ 81.3 million, and $ 109.0 million for the years ended December 31, 2021, 2020, and 2019, respectively. The Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable unit basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the same time demand weakened due to the impact of the COVID-19 pandemic. The Partnership determined these events and circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and 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 rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved F-11 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded. Other Property and Equipment Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from 3 years to 7 years. Depreciation and amortization expense totaled $ 0.6 million, $ 0.7 million, and $ 0.6 million for the years ended December 31, 2021, 2020, and 2019, respectively. Repairs and Maintenance The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable. Accrued Liabilities Accrued liabilities consisted of the following: December 31, 2021 2020 (in thousands) Accrued liabilities: Accrued capital expenditures $ 849 $ — Accrued incentive compensation 8,978 5,058 Accrued property taxes 5,704 8,432 Accrued other 2,058 2,078 Total accrued liabilities $ 17,589 $ 15,568 Debt Issuance Costs Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issuance costs was $ 1.6 million, $ 1.0 million, and $ 1.0 million for the years ended December 31, 2021, 2020, and 2019, respectively, and is included in interest expense in the consolidated statements of operations. Asset Retirement Obligations Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset. Leases 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 F-12 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS liabilities in the consolidated balance sheets. As of December 31, 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. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments. The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Partnership will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities. Revenues from Contracts with Customers 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. Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership recognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. 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. 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. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Allocation of transaction price to remaining performance obligations 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 unsatisfied performance obligation. 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. F-13 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2021 and 2020, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial. Income Taxes The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxes are not material. Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas. Fair Value of Financial Instruments The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31, 2021 and 2020 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurements for further discussion. Incentive Compensation Incentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant date fair values. Liability awards are awards that are expected to be settled in cash or an unknown number of common units on their vesting dates. 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. See Note 9 – Incentive Compensation for additional discussion. F-14 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 3 — ASSET RETIREMENT OBLIGATIONS 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. The Partnership estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability for the periods presented: For the year ended December 31, 2021 2020 (in thousands) Beginning asset retirement obligations $ 17,717 $ 16,084 Liabilities incurred 463 1,030 Liabilities settled ( 351 ) ( 324 ) Accretion expense 1,073 1,131 Revisions in estimated costs 45 ( 151 ) Dispositions ( 5,663 ) ( 53 ) Ending asset retirement obligations $ 13,284 $ 17,717 Current asset retirement obligations $ 723 $ 340 Non-current asset retirement obligations $ 12,561 $ 17,377 NOTE 4 — OIL AND NATURAL GAS PROPERTIES Divestitures 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. 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. F-15 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Acquisitions 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 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. 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 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. 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. F-16 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 above. 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. 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. Impairment of Oil and Natural Gas Properties Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compared the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When 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. F-17 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. 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. NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. 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. Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership's derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of December 31, 2021 and 2020. See Note 6 – Fair Value Measurements for further discussion. The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. 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. F-18 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The tables below summarize the fair value and classification of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date: As of December 31, 2021 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ — $ — $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ — $ — $ — Liabilities: Current liability Commodity derivative liabilities $ 51,544 $ — $ 51,544 Long-term liability Commodity derivative liabilities 2,001 — 2,001 Total liabilities $ 53,545 $ — $ 53,545 As of December 31, 2020 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 6,362 $ ( 5,213 ) $ 1,149 Long-term asset Deferred charges and other long-term assets — — — Total assets $ 6,362 $ ( 5,213 ) $ 1,149 Liabilities: Current liability Commodity derivative liabilities $ 24,531 $ ( 5,213 ) $ 19,318 Long-term liability Commodity derivative liabilities 1,848 — 1,848 Total liabilities $ 26,379 $ ( 5,213 ) $ 21,166 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: For the year ended December 31, Derivatives not designated as hedging instruments 2021 2020 2019 (in thousands) Beginning fair value of commodity derivative instruments $ ( 20,017 ) $ 15,221 $ 48,038 Gain (loss) on oil derivative instruments ( 75,180 ) 36,091 ( 34,728 ) Gain (loss) on natural gas derivative instruments ( 71,294 ) 10,020 29,773 Net cash paid (received) on settlements of oil derivative instruments 66,418 ( 56,487 ) ( 8,536 ) Net cash paid (received) on settlements of natural gas derivative instruments 46,528 ( 24,862 ) ( 19,326 ) Net change in fair value of commodity derivative instruments ( 33,528 ) ( 35,238 ) ( 32,817 ) Ending fair value of commodity derivative instruments $ ( 53,545 ) $ ( 20,017 ) $ 15,221 F-19 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Partnership had the following open derivative contracts for oil as of December 31, 2021: Volume (Bbl) Weighted Average Price (per Bbl) Range (per Bbl) Period and Type of Contract Low High Oil Swap Contracts: 2021 Fourth quarter 220,000 $ 38.97 $ 32.64 $ 46.50 2022 First quarter 480,000 60.14 55.29 65.50 Second quarter 480,000 60.14 55.29 65.50 Third quarter 480,000 60.14 55.29 65.50 Fourth quarter 480,000 60.14 55.29 65.50 The Partnership had the following open derivative contracts for natural gas as of December 31, 2021: Volume (MMBtu) Weighted Average Price (per MMBtu) Range (per MMBtu) Period and Type of Contract Low High Natural Gas Swap Contracts: 2022 First quarter 7,920,000 $ 2.98 $ 2.80 $ 3.15 Second quarter 8,000,000 2.99 2.80 3.15 Third quarter 8,080,000 2.99 2.80 3.15 Fourth quarter 8,080,000 2.99 2.80 3.15 2023 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: 2022 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 2023 First quarter 180,000 80.40 78.00 82.80 F-20 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: 2022 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 2023 First quarter 900,000 4.30 4.30 4.30 NOTE 6 — FAIR VALUE MEASUREMENTS Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 — Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 — Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). 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 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. The carrying value of the Partnership's cash and cash equivalents, receivables and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of December 31, 2021 and 2020 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for further discussion. F-21 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 (In thousands) As of December 31, 2021 Financial Assets Commodity derivative instruments $ — $ — $ — $ — $ — Financial Liabilities Commodity derivative instruments — 53,545 — — 53,545 As of December 31, 2020 Financial Assets Commodity derivative instruments $ — $ 6,362 $ — $ ( 5,213 ) $ 1,149 Financial Liabilities Commodity derivative instruments — 26,379 — ( 5,213 ) 21,166 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership's fair value assessments for recent acquisitions are included in Note 4 — Oil and Natural Gas Properties. Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. The Partnership estimated the fair value of the impaired properties using published forward commodity price curves as of the measurement date of March 31, 2020, considering locational and quality differentials based on a review of historical realizations, and using an annual discount rate of 8 %. Fair Value Measurements Using Level 1 Level 2 Level 3 Impairment (in thousands) Year Ended December 31, 2021 Impaired oil and natural gas properties $ — $ — $ — $ — Year Ended December 31, 2020 Impaired oil and natural gas properties $ — $ — $ 2,044 $ 51,031 Year Ended December 31, 2019 Impaired oil and natural gas properties $ — $ — $ — $ — The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. Changes to these estimates, particularly related to economic reserves, future commodity prices, and timing of future production could result in additional impairment charges in the future. There were no significant changes in valuation techniques or related inputs for the years ended December 31, 2021 and 2020. There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2021 and 2019. F-22 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 7 — SIGNIFICANT CUSTOMERS The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. XTO Energy represented approximately 19 %, 20 %, and 18 % of total oil and natural gas revenue for the years ended December 31, 2021, 2020, and 2019, respectively. If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests. The loss of any single customer is mitigated by the Partnership’s diversified customer base. NOTE 8 — CREDIT FACILITY 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 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 also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10 % of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5 % of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the 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 next semi-annual redetermination is scheduled for April 2022. 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 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. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. 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. The aggregate principal balance outstanding was $ 89.0 million and $ 121.0 million at December 31, 2021 and 2020, respectively. 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. F-23 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 9 — INCENTIVE COMPENSATION Overview The board of directors of the Partnership’s general partner (the "Board") established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to the Partnership’s common units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vesting terms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof. Incentive compensation expense is included in 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). Cash Awards 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. Restricted Unit Awards Restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. 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 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. Consistent with previous awards the 2021 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2024. 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. F-24 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, 2021. Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2020 593,990 $ 13.65 Granted 465,048 9.25 Vested ( 294,104 ) 14.96 Forfeited ( 2,942 ) 10.06 Unvested at December 31, 2021 761,992 10.47 The weighted-average grant-date fair value per unit for unit-based awards was $ 9.25 , $ 9.97 , and $ 17.09 for the years ended December 31, 2021, 2020, and 2019, respectively. As of December 31, 2021, unrecognized compensation cost associated with restricted unit awards was $ 3.9 million, which the Partnership expects to recognize over a weighted-average period of 1.74 years. The fair value of units vested for the years ended December 31, 2021, 2020, and 2019 was $ 2.3 million, $ 7.5 million, and $ 12.7 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2021, 2020, and 2019. Performance Unit Awards The Compensation Committee also approves grants of restricted performance units that are subject to both performance-based and service-based vesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Partnership’s performance over each of the three calendar year performance periods commencing January 1 of the first calendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. 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. The following table summarizes information about performance units for the year ended December 31, 2021. Performance units Number of Units Weighted-Average Grant-Date Fair Value per Unit Unvested at December 31, 2020 882,310 $ 14.96 Granted 1 484,943 9.61 Vested ( 300,868 ) 17.95 Forfeited ( 3,898 ) 10.83 Unvested at December 31, 2021 1,062,487 11.68 1 Includes 19,895 of additional performance units issued based on the final performance multiplier for awards that vested in the period. The weighted-average grant-date fair value per unit for performance unit awards was $ 9.61 , $ 10.95 , and $ 16.84 for the years ended December 31, 2021, 2020, and 2019, respectively. Unrecognized compensation cost associated with performance unit awards was $ 4.7 million as of December 31, 2021, which the Partnership expects to recognize over a weighted-average period of 1.76 years. The fair value of performance units vested for the years ended December 31, 2021, 2020 and 2019 was $ 2.8 million, $ 5.5 million and $ 22.7 million, respectively. F-25 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 2021, 2020, and 2019. Year Ended December 31, Incentive compensation expense 2021 2020 2019 (In thousands) Cash — short and long-term incentive plan $ 6,824 $ 2,962 $ 5,593 Equity-based compensation — restricted common and subordinated units 4,146 4,688 10,751 Equity-based compensation — restricted performance units 6,320 ( 2,417 ) 7,386 Board of Directors incentive plan 1,752 1,456 2,347 Total incentive compensation expense $ 19,042 $ 6,689 $ 26,077 NOTE 10 — EMPLOYEE BENEFIT PLANS Black Stone Natural Resources Management Company, a subsidiary of the Partnership, sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred pre-tax or post-tax contributions up to 90 % of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Partnership makes matching contributions of 100% of employee contributions, up to 5 % of compensation. These matching contributions are subject to a graded vesting schedule, with 33 % vested after one year , 66 % vested after two years and 100 % vested after three years of service with the Partnership. Following three years of service, future Partnership matching contributions vest immediately. The Partnership’s contributions were $ 0.5 million, $ 0.5 million, and $ 0.7 million for the years ended December 31, 2021, 2020, and 2019, respectively. NOTE 11 — COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements and no provision for potential remediation costs has been recorded. Litigation From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of December 31, 2021 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations. NOTE 12 — PREFERRED UNITS Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $ 20.3926 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 F-26 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $ 10 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $ 298.4 million, including accrued distributions of $ 5.3 million, as of December 31, 2021 and 2020. 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. NOTE 13 — EARNINGS PER UNIT The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. 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. 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. F-27 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES 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, 2021 2020 2019 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 181,987 $ 121,819 $ 214,368 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 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — Common units 160,987 100,819 169,375 Subordinated units — — 23,993 $ 160,987 $ 100,819 $ 193,368 Weighted average common units outstanding: Weighted average common units outstanding (basic) 208,181 206,705 168,230 Effect of dilutive securities 109 114 146 Weighted average common units outstanding (diluted) 208,290 206,819 168,376 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: Per common unit (basic) $ 0.77 $ 0.49 $ 1.01 Per subordinated unit (basic) — — 0.64 Per common unit (diluted) 1 0.77 0.49 1.01 Per subordinated unit (diluted) 2 — — 0.64 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: For the Year Ended December 31, 2021 2020 2019 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,968 14,968 14,968 14,968 14,968 14,968 F-28 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. 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: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7 % per annum, subject to certain adjustments; and • 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. F-29 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES 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. NOTE 15 — SUBSEQUENT EVENTS Distribution 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 will be paid on February 23, 2022 to unitholders of record at the close of business on February 16, 2022. F-30 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Geographic Area of Operation All the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Texas, Louisiana, and North Dakota. However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves are presented on a consolidated basis. Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2021 2020 2019 (in thousands) Acquisition Costs of Properties 1 : Proved $ 4,965 $ — $ 2,288 Unproved 15,559 28 41,643 Exploration Costs 1,049 — 3 Development Costs 1 3,964 2,742 34,617 Total $ 25,537 $ 2,770 $ 78,551 1 See Note 4 – Oil and Natural Gas Properties for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment. Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below: As of December 31, 2021 2020 (in thousands) Proved properties 1 $ 2,064,232 $ 2,220,354 Unproved properties 937,395 937,464 Total 3,001,627 3,157,818 Accumulated depreciation, depletion, amortization, and impairment ( 1,869,731 ) ( 1,987,332 ) Oil and natural gas properties, net $ 1,131,896 $ 1,170,486 1 Proved properties include capitalized costs related to farmout wells not yet assigned. F-31 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED Oil and Natural Gas Reserve Information The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. For estimates of oil reserves, the average WTI spot oil prices used were $ 66.55 , $ 39.54 , and $ 55.85 per barrel as of December 31, 2021, 2020, and 2019, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $ 3.60 , $ 1.99 , and $ 2.58 per MMBTU as of December 31, 2021, 2020, and 2019, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties were $ 63.17 per barrel for oil and $ 3.37 per Mcf for natural gas as of December 31, 2021, $ 36.43 per barrel for oil and $ 1.60 per Mcf for natural gas as of December 31, 2020, and $ 52.15 per barrel for oil and $ 2.36 per Mcf for natural gas as of December 31, 2019. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2018 17,567 314,020 69,904 Revisions of previous estimates 1 951 19,136 4,140 Purchases of minerals in place 2 46 279 92 Extensions, discoveries and other additions 3 3,263 53,158 12,123 Production ( 4,777 ) ( 77,635 ) ( 17,716 ) Net proved reserves at December 31, 2019 17,050 308,958 68,543 Revisions of previous estimates 1 2,490 ( 22,337 ) ( 1,233 ) Sales of minerals in place 4 ( 1,262 ) ( 3,132 ) ( 1,784 ) Extensions, discoveries and other additions 3 1,569 24,667 5,680 Production ( 3,895 ) ( 67,945 ) ( 15,219 ) 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 2 272 216 308 Sales of minerals in place 4 ( 135 ) ( 6,194 ) ( 1,167 ) Extensions, discoveries and other additions 3 1,911 32,592 7,343 Production ( 3,646 ) ( 61,445 ) ( 13,887 ) Net proved reserves at December 31, 2021 19,171 243,917 59,824 Net Proved Developed Reserves December 31, 2019 17,050 263,371 60,945 December 31, 2020 15,952 230,411 54,354 December 31, 2021 19,111 224,222 56,481 Net Proved Undeveloped Reserves December 31, 2019 — 45,587 7,598 December 31, 2020 — 9,800 1,633 December 31, 2021 60 19,695 3,343 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. 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. In 2020 these were primarily in the Permian Basin and in 2021 these were primarily in the Anadarko Basin. F-32 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion. Year Ended December 31, 2021 2020 2019 (in thousands) Future cash inflows $ 2,033,256 $ 965,007 $ 1,619,147 Future production costs ( 206,785 ) ( 99,124 ) ( 177,550 ) Future development costs ( 43,500 ) ( 59,692 ) ( 54,132 ) Future income tax expense ( 6,322 ) ( 3,019 ) ( 5,244 ) Future net cash flows (undiscounted) 1,776,649 803,172 1,382,221 Annual discount 10% for estimated timing ( 804,527 ) ( 309,675 ) ( 534,327 ) Total $ 972,122 $ 493,497 $ 847,894 The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2021 2020 2019 (in thousands) Standardized measure, beginning of year $ 493,497 $ 847,894 $ 1,087,616 Sales, net of production costs ( 428,577 ) ( 230,062 ) ( 384,745 ) Net changes in prices and production costs related to future production 537,659 ( 242,634 ) ( 229,651 ) Extensions, discoveries and improved recovery, net of future production and development costs 148,732 65,903 186,424 Previously estimated development costs incurred during the period 245 — — Revisions of estimated future development costs 2,254 ( 1,530 ) 1,198 Revisions of previous quantity estimates, net of related costs 210,039 ( 24,195 ) 51,405 Accretion of discount 49,530 85,109 109,158 Purchases of reserves in place, less related costs 9,254 — 1,730 Sales of reserves in place 1 ( 1,037 ) ( 26,795 ) ( 3,323 ) Changes in timing and other ( 49,474 ) 19,807 28,082 Net increase (decrease) in standardized measures 478,625 ( 354,397 ) ( 239,722 ) Standardized measure, end of year $ 972,122 $ 493,497 $ 847,894 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. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. F-33