What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2021-02-23 compared with 2020-02-25 · 170 added, 253 removed, 1126 unchanged (27% of the section changed)

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Exhibit Number Description

Purchase and Sale Agreement, dated as of November 22, 2017, by and among Noble Energy Inc., Noble Energy Wyco, LLC, Noble Energy US Holdings, LLC, Rosetta Resources Operating LP, and Black Stone Minerals Company, L.P.

(incorporated herein by reference to Exhibit 2.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on November 29, 2017 (SEC File No.

Certificate of Limited Partnership of Black Stone Minerals, L.P.

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

Description of Securities

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.

Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P.

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Second Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of October 31, 2018 (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 5, 2018 (SEC File No.

Third Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders dated as of May 1, 2020.

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

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

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* Filed herewith.

** Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K.

The Partnership agrees to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.

^ Management contract or compensatory plan or arrangement.

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Smajstrla (Principal Accounting Officer)

/s/ William G.

Bardel Director February 25, 2020

Barth Director February 23, 2021

Mark DeWalch Director February 23, 2021

Haeflinger Director February 25, 2020

Director February 23, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

Black Stone Minerals, L.P.

and subsidiaries

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

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

Description of the Matter At December 31, 2019, the net book value of the Partnership’s oil and natural gas properties was $1,432 million, and depreciation, depletion and amortization (“DD&A”) expense was $109 million for the year then ended.

As discussed in Note 2, under the successful efforts method of accounting, DD&A is recorded based on the units-of-production method.

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

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

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.

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

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

The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

Proved oil and natural gas reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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Because of the complexity involved in estimating oil and natural gas reserves, management used independent petroleum engineers to prepare the oil and natural gas reserve estimates as of December 31, 2020.

Auditing the Partnership’s DD&A calculation is especially complex because of the use of the work of the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and natural gas reserves.

How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and natural gas reserves.

Auditing the Partnership’s DD&A and impairment calculations is especially complex because of the use of the work of the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and natural gas reserves.

How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls over its process to calculate DD&A and impairment, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and natural gas reserves.

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

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

Revenues from Contracts with Customers Accrual

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

Black Stone Minerals, L.P.

and subsidiaries

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760,606 798,443

Partners' equity — subordinated units, zero and 96,329 units outstanding at December 31, 2019 and 2018, respectively

TOTAL EQUITY 760,606 798,443

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Depreciation, depletion, and amortization 82,018 109,584 122,653

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

General and administrative 42,983 63,353 76,712

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Repurchases of common and subordinated units ( 623 ) ( 23 ) ( 10,879 ) ( 342 ) — ( 11,221 )

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

Issuance of common units, net of offering costs 2,244 — 40,537 — — 40,537

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Charges to partners' equity for accrued distribution equivalent rights — — ( 3,698 ) — — ( 3,698 )

Net income (loss) — — 101,891 55,296 ( 34 ) 157,153

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

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

Net income (loss) — — 175,675 119,861 24 295,560

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Depreciation, depletion, and amortization 82,018 109,584 122,653

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

Accretion of asset retirement obligations 1,131 1,117 1,103

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Proceeds from farmouts of oil and natural gas properties 4,198 61,504 124,522

NET CASH USED IN INVESTING ACTIVITIES ( 48,623 ) ( 163,804 ) ( 454,249 )

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 151,246 ( 48,623 ) ( 163,804 )

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from issuance of common units, net of offering costs — ( 43 ) 40,537

Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs — — 293,469

Distributions to common and subordinated unitholders ( 140,343 ) ( 304,439 ) ( 250,121 )

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The Partnership also owns non-operated working interests in certain oil and natural gas properties.

On May 6, 2015, the Partnership completed its initial public offering (the "IPO") of 22,500,000 common units representing limited partner interests.

The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."

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Securities and Exchange Commission ("SEC").

The consolidated financial statements include the consolidated results of the Partnership, which also includes the results of the Noble Acquisition (as defined below) for the period from November 28, 2017 through December 31, 2019, as discussed in Note 4 – Oil and Natural Gas Properties.

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.

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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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

impairment of oil and natural gas properties.

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

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

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, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards.

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

The Partnership determined these events and circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired as of March 31, 2020.

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

There was no impairment of proved oil and natural gas properties for the years ended December 31, 2019 and 2018.

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

See Note 6 - Fair Value Measurements for further discussion.

The carrying value of unproved properties, including unleased mineral

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

carrying value exceeds the estimated recoverable value.

The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

There was no impairment of unproved properties for the years ended December 31, 2020, 2019, and 2018.

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Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.

On January 1, 2019, the Partnership adopted ASC 842, Leases , using the modified retrospective method.

ASC 842 requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous

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.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership used January 1, 2019, the beginning of the period of adoption, as its date of initial application.

The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.

The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019.

ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of December 31, 2019 and were not considered material to the Partnership.

There was no related impact on the consolidated statement of operations.

The standard had no impact on the Partnership’s debt covenant compliance under existing agreements.

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

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A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period.

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

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received.

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

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.

Production imbalances

The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606.

As of January 1, 2018, these amounts were de minimis.

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.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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Fair Value of Financial Instruments

The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31,

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2019 and 2018 due to the short-term maturity of these instruments.

See Note 6 – Fair Value Measurements for further discussion.

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See Note 9 – Incentive Compensation for additional discussion.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements.

As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements.

In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date.

Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements.

For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements.

The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years.

The Partnership does not believe the adoption of this update will have an impact on its financial position, results of operations, or liquidity.

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

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

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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NOTE 4 — OIL AND NATURAL GAS PROPERTIES

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.

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

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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.

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

Noble Acquisition

On November 28, 2017 (the "Close Date"), Black Stone Minerals Company, L.P.

("BSMC"), a wholly owned subsidiary of BSM, closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition."

The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross ( 140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota.

The Partnership funded the $ 335 million purchase price (before customary post-closing adjustments) using (i) approximately $ 300 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group ("the Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $ 35 million from borrowings under its Credit Facility.

See additional discussion of the Series B cumulative convertible preferred units in Note 12 – Preferred Units.

The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The final determination of fair value was completed in 2018 after post-closing purchase price adjustments were finalized.

Since December 31, 2017, the Partnership has recorded an adjustment to the purchase price to reduce the amount allocated to unproved properties by $ 3.2 million, which reduces the Acquisitions of oil and natural gas properties line item of the consolidated statement of cash flows for the year ended December 31, 2018.

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the final allocation of the fair value of the assets acquired and the acquisition-related costs.

Assets Acquired

Proved Unproved Net Working Capital Total Fair Value Cash Consideration Paid 1

Acquisition-Related Costs 2

(in thousands)

Noble Assets $ 68,877 $ 256,542 $ 5,917 $ 331,336 $ 331,336 $ 247

1 Represents cash consideration paid on the Close Date, as adjusted for the $ 3.2 million purchase price adjustment recorded during the year ended December 31, 2018.

2 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount.

Significant inputs to the valuation of oil and natural gas properties include estimates of:

(i) oil and natural gas reserves;

(ii) future commodity prices;

(iii) estimated future cash flows;

and (iv) market-based weighted average cost of capital.

These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

Actual and Pro Forma Impact of Noble Acquisition (Unaudited)

Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the year ended December 31, 2017 was $ 2.8 million.

The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016.

For the Year Ended December 31,

(in thousands, except per unit amounts)

Revenue and other income $ 468,103 $ 288,772

Net income (loss) $ 178,970 $ 33,264

Net income (loss) attributable to noncontrolling interests 34 12

Distributions on Series A redeemable preferred units ( 3,117 ) ( 5,763 )

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

Net income (loss) attributable to the general partner and common and subordinated units $ 154,887 $ 6,513

Allocation of net income (loss):

General partner interest — —

Common units 99,776 20,696

Subordinated units 55,111 ( 14,183 )

$ 154,887 $ 6,513

Net income (loss) attributable to limited partners per common and subordinated unit:

Per common unit (basic) $ 1.02 $ 0.22

Per subordinated unit (basic) $ 0.58 $ ( 0.15 )

Per common unit (diluted) $ 1.02 $ 0.22

Per subordinated unit (diluted) $ 0.58 $ ( 0.15 )

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable.

The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2016.

In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company.

The unaudited pro forma consolidated results reflect the following pro forma adjustments:

• Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.

• Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.

• Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.

• The Series B cumulative convertible preferred units were excluded from the calculation of pro forma diluted earnings per common unit for the periods presented above due to their antidilutive effect under the if-converted method.

• The Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.

2017 Acquisitions

In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests, which were also considered business combinations, during the year ended December 31, 2017.

These acquisitions were primarily focused in the Delaware Basin and East Texas.

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

The following table summarizes these acquisitions:

Assets Acquired Consideration Paid

Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued Acquisition-Related Costs 1

(in thousands)

January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 27,380 $ 12,026 $ 1,162

June 5,006 45,477 — 50,483 4,802 45,681 1,481

August 3,277 9,984 — 13,261 4,289 8,972 107

September 3,120 — — 3,120 3,120 — —

Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 39,591 $ 66,679 $ 2,750

1 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

In addition, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers in East Texas as reflected in the table below.

The cash portion of the consideration paid for these acquisitions was funded via borrowings under the Partnership's Credit Facility.

Assets Acquired Consideration Paid

Unproved Cash Fair Value of Common Units Issued

(in thousands)

Q1 2017 $ 21,189 $ 21,017 $ 172

Q2 2017 13,329 13,329 —

Q3 2017 19,946 15,205 4,741

Q4 2017 2,267 2,137 130

Total acquired $ 56,731 $ 51,688 $ 5,043

BLACK STONE MINERALS, L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Farmout Agreements

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Canaan Farmout

On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc.

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

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

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

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

A total of 20 wells were drilled over an initial phase, beginning with wells spud after January 1, 2017.

Canaan elected to participate in an additional phase that began in September 2018 and continues for the earlier of 2 years or until 20 wells have been drilled.

As of December 31, 2019, a total of 17 wells have been drilled during the second phase.

After the completion of the second phase, Canaan will have the option to elect to participate in a similar third phase.

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

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

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

The Partnership receives an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement.

From the inception of the agreement through December 31, 2019, the Partnership has received $ 90.0 million from Canaan under the agreement as reimbursement for capital costs associated with farmed-out working interests.

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

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

As of December 31, 2019, $ 0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Canaan.

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

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

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

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pivotal Farmout

On November 21, 2017, the Partnership entered into a farmout agreement with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC.

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

Pivotal will earn the Partnership's remaining working interest in wells operated by XTO Energy in San Augustine County, Texas not covered by the Canaan Farmout ( 10 % working interest on an 8/8th basis), as well as 100 % of the Partnership's working interests (ranging from approximately 12.5 % to 25 % on an 8/8ths basis) in wells operated by BPX Energy in San Augustine and Angelina counties, Texas.

Initially, Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement.

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

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

Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement.

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

From the inception of the agreement through December 31, 2019, a total of 68 wells have been drilled in the contract area and the Partnership has received $ 115.2 million from Pivotal under the agreement as reimbursement for capital costs associated with farmed-out working interests.

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

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

As of December 31, 2020, a total of 68 wells have been spud in the contract area subject to the First Pivotal Farmout.

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

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

The Partnership remains engaged with Pivotal around farmout opportunities with potential new operators in the area forfeited by BPX Energy.

As of December 31, 2018, $ 11.6 million and $ 41.2 million were included in the Other long-term liability line item of the consolidated balance sheet related to the farmout agreements with Canaan and Pivotal, respectively.

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

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

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

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

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

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

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

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

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

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

As of December 31, 2020, a total of 2 wells have been spud in the contract area subject to the Second Pivotal Farmout.

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

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

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

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

XTO Completions Agreement

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

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

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

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.

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

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

See Note 6 - Fair Value Measurements for further discussion.

NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

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

As of December 31, 2019, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Partnership's Credit Facility.

As of December 31, 2020, the Partnership had eight counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Partnership's Credit Facility.

BLACK STONE MINERALS, L.P.

51 unchanged sentences

Fourth quarter 70,000 56.43 67.14

First quarter 210,000 $ 56.43 $ 67.14

Second quarter 210,000 56.43 67.14

Third quarter 210,000 56.43 67.14

Fourth quarter 210,000 56.43 67.14

The Partnership had the following open derivative contracts for natural gas as of December 31, 2020:

6 unchanged sentences

Fourth quarter 10,120,000 2.69 2.52 3.08

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 — FAIR VALUE MEASUREMENTS

9 unchanged sentences

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

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

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

There were no transfers into, or out of, the three levels of the fair value hierarchy for the years ended December 31, 2020 and 2019.

20 unchanged sentences

Commodity derivative instruments — 4,520 — ( 4,343 ) 177

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

4 unchanged sentences

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 nonrecurring basis using the income approach when assessing for impairment.

When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability.

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

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements Using

Level 1 Level 2 Level 3 Impairment

(in thousands)

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 $ — $ — $ — $ —

Year Ended December 31, 2018

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, 2020 and 2019.

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended December 31, 2019, 2018, and 2017.

There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the years ended 2019 and 2018.

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 18 %, 15 %, and 21 % of total oil and natural gas revenue for the years ended December 31, 2019, 2018, and 2017.

XTO Energy represented approximately 20 %, 18 %, and 15 % of total oil and natural gas revenue for the years ended December 31, 2020, 2019, and 2018, respectively.

If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests.

5 unchanged sentences

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.

Effective May 4, 2018, the borrowing base redetermination increased the borrowing base from $ 550.0 million to $ 600.0 million.

Effective October 31, 2018, the borrowing base was further increased to $ 675.0 million and remained at that level until the most recent redetermination, effective October 23, 2019, which reduced the borrowing base to $ 650.0 million.

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.

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

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

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

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

The next semi-annual redetermination is scheduled for April 2021.

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

1 unchanged sentence

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

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

The weighted-average interest rate of the Credit Facility was 2.40 % and 4.05 % as of December 31, 2020 and 2019, respectively.

19 unchanged sentences

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.

Certain employees are entitled to receive cash bonuses based on service criteria over a four -year requisite service period ending in 2019.

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

17 unchanged sentences

Vested ( 569,916 ) 17.93

Converted — —

Forfeited ( 172,632 ) 17.35

23 unchanged sentences

Unrecognized compensation cost associated with performance unit awards was $ 2.0 million as of December 31, 2020, which the Partnership expects to recognize over a weighted-average period of 1.71 years.

The fair value of performance units vested for the years ended December 31, 2019, and 2018 was $ 22.7 million, and $ 1.5 million, respectively.

No performance units vested for the year ended December 31, 2017.

The fair value of performance units vested for the years ended December 31, 2020, 2019 and 2018 was $ 5.5 million, $ 22.7 million and $ 1.5 million, respectively.

BLACK STONE MINERALS, L.P.

1 unchanged sentence

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Incentive Compensation

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, 2020, 2019, and 2018.

9 unchanged sentences

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 contributions up to 90 % of their annual compensation, not to exceed annual limits established by the Internal Revenue Service.

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.

7 unchanged sentences

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.

Put Option Related to Noble Acquisition

By acquiring 100 % of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100 % interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin").

Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 45.33 % and 42.63 % of the mineral interests held of record by Holdings and Temin, respectively, as of December 31, 2019.

Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice.

The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith.

As of December 31, 2019, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.

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, 2020 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 — PREFERRED UNITS

5 unchanged sentences

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $ 20.2 million, including accrued unpaid yield, and 6,624 Series A redeemable preferred units totaling $ 6.6 million were converted into the equivalent of 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016.

Series B Cumulative Convertible Preferred Units

8 unchanged sentences

The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain redemption provisions are outside the control of the Partnership.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13 — EARNINGS PER UNIT

2 unchanged sentences

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 no t material.

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.

3 unchanged sentences

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31,

25 unchanged sentences

Per subordinated unit (diluted) 2

0.64 1.25 0.56

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

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

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

6 unchanged sentences

14,968 14,968 189

Potentially dilutive securities (subordinated units):

Series A redeemable preferred units on an as-converted basis — — 1,304

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — COMMON AND SUBORDINATED UNITS

10 unchanged sentences

• second , to the holders of common units.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

4 unchanged sentences

Per subordinated unit — 0.74 1.13

0.74 1.13 0.79

1 For the six months ended December 31, 2019 there were no distributions on subordinated units as all subordinated units converted into common units on May 24, 2019.

Common Unit Repurchase Program

1 unchanged sentence

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.

In 2019, the Partnership repurchased a total of 136,665 common units for an aggregate cost of $ 2.2 million.

The Partnership made no repurchases under this program for the year ended December 31, 2020.

As of December 31, 2020, the Partnership has repurchased $ 4.2 million in common units under the repurchase program since inception.

4 unchanged sentences

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

Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” 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.

Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market”

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.

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

2 unchanged sentences

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

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

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

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

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

4 unchanged sentences

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

General and Administrative Expense Reductions

The Partnership has taken significant steps to reduce its general and administrative expenses, including broad workforce reductions and lower Board and executive compensation levels.

The Partnership expects to incur a one-time cash charge of approximately $ 5 million in the first quarter of 2020 associated with severance agreements for affected employees.

BLACK STONE MINERALS, L.P.

AND SUBSIDIARIES

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED

34 unchanged sentences

The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves.

These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership.

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 $ 39.54 , $ 55.85 , and $ 65.56 per barrel as of December 31, 2020, 2019, and 2018, 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 $ 1.99 , $ 2.58 , and $ 3.10 per MMBTU as of December 31, 2020, 2019, and 2018, 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 $ 36.43 per barrel for oil and $ 1.60 per Mcf for natural gas as of December 31, 2020, $ 52.15 per barrel for oil and $ 2.36 per Mcf for natural gas as of December 31, 2019, and $ 62.81 per barrel for oil and $ 2.98 per Mcf for natural gas as of December 31, 2018.

Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe)

3 unchanged sentences

Purchases of minerals in place 2

2,335 31,323 7,555

Extensions, discoveries and other additions 3

11 unchanged sentences

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

Purchases of minerals in place 4

Sales of minerals in place 4

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

Extensions, discoveries and other additions 3

11 unchanged sentences

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

The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells.

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

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

The most notable revisions in 2018 and 2019 are related to well performance in certain Haynesville/ Bossier wells.

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

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

5 As of December 31, 2018 and 2019, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries.

As of December 31, 2017, proved developed reserves of 61 MBoe were attributable to noncontrolling interests.

6 As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests.

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

4 Includes divestitures of mineral and royalty reserves primarily in the Permian Basin.

Standardized Measure of Discounted Future Net Cash Flows

16 unchanged sentences

Annual discount 10% for estimated timing ( 309,675 ) ( 534,327 ) ( 663,814 )

$ 847,894 $ 1,087,616 $ 862,649

1 Includes standardized measure of discounted future net cash flows of approximately $ 0.5 million for December 31, 2017 attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.

Total $ 493,497 $ 847,894 $ 1,087,616

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

11 unchanged sentences

Purchases of reserves in place, less related costs — 1,730 8,975

Sales of reserves in place 1

( 26,795 ) ( 3,323 ) ( 1,137 )

Changes in timing and other 19,807 28,082 ( 47,906 )

1 unchanged sentence

Standardized measure, end of year $ 493,497 $ 847,894 $ 1,087,616

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

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

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

42 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures