UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM						10-Q

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, ~~2022~~2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period _______________ to _______________

Commission File Number: 001-37362


Black Stone Minerals, L.P.
(Exact name of registrant as specified in its charter)


Delaware		47-1846692
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 2020
Houston,	Texas	77002
(Address of principal executive offices)		(Zip code)


(713)			445-3200
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units Representing Limited Partner Interests

BSM

New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of April ~~29, 2022,~~28, 2023, there were ~~209,398,324~~209,966,519 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
ASSETS	ASSETS					ASSETS
CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash and cash equivalents	Cash and cash equivalents	$	6,653	$	8,876	Cash and cash equivalents	$	19,150	$	4,307
Accounts receivable	Accounts receivable	99,463		97,142		Accounts receivable	94,186		135,697

Commodity derivative assets						Commodity derivative assets	68,367		31,472

Prepaid expenses and other current assets	Prepaid expenses and other current assets	1,866		1,956		Prepaid expenses and other current assets	2,087		1,905
TOTAL CURRENT ASSETS	TOTAL CURRENT ASSETS	107,982		107,974		TOTAL CURRENT ASSETS	183,790		173,381
PROPERTY AND EQUIPMENT	PROPERTY AND EQUIPMENT					PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $937,395 and $937,395 at March 31, 2022 and December 31, 2021, respectively		3,003,776		3,001,627
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $909,344 and $909,344 at March 31, 2023 and December 31, 2022, respectively						Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $909,344 and $909,344 at March 31, 2023 and December 31, 2022, respectively	3,005,740		3,003,907
Accumulated depreciation, depletion, amortization, and impairment	Accumulated depreciation, depletion, amortization, and impairment	(1,880,493)		(1,869,731)		Accumulated depreciation, depletion, amortization, and impairment	(1,927,896)		(1,916,919)
Oil and natural gas properties, net	Oil and natural gas properties, net	1,123,283		1,131,896		Oil and natural gas properties, net	1,077,844		1,086,988
Other property and equipment, net of accumulated depreciation of $13,000 and $12,931 at March 31, 2022 and December 31, 2021, respectively		1,262		1,440
Other property and equipment, net of accumulated depreciation of $13,630 and $13,461 at March 31, 2023 and December 31, 2022, respectively						Other property and equipment, net of accumulated depreciation of $13,630 and $13,461 at March 31, 2023 and December 31, 2022, respectively	1,111		1,259
NET PROPERTY AND EQUIPMENT	NET PROPERTY AND EQUIPMENT	1,124,545		1,133,336		NET PROPERTY AND EQUIPMENT	1,078,955		1,088,247
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	6,042		6,611		DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	8,919		9,454
TOTAL ASSETS	TOTAL ASSETS	$	1,238,569	$	1,247,921	TOTAL ASSETS	$	1,271,664	$	1,271,082
LIABILITIES, MEZZANINE EQUITY, AND EQUITY	LIABILITIES, MEZZANINE EQUITY, AND EQUITY					LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES
Accounts payable	Accounts payable	$	2,380	$	5,944	Accounts payable	$	4,963	$	6,773
Accrued liabilities	Accrued liabilities	5,960		17,589		Accrued liabilities	6,724		19,729
Commodity derivative liabilities	Commodity derivative liabilities	138,028		51,544		Commodity derivative liabilities	—		3,243
Other current liabilities	Other current liabilities	2,070		2,063		Other current liabilities	1,098		989
TOTAL CURRENT LIABILITIES	TOTAL CURRENT LIABILITIES	148,438		77,140		TOTAL CURRENT LIABILITIES	12,785		30,734
LONG–TERM LIABILITIES	LONG–TERM LIABILITIES					LONG–TERM LIABILITIES
Credit facility	Credit facility	69,000		89,000		Credit facility	—		10,000
Accrued incentive compensation	Accrued incentive compensation	682		838		Accrued incentive compensation	801		1,884
Commodity derivative liabilities	Commodity derivative liabilities	4,293		2,001		Commodity derivative liabilities	1,052		16
Asset retirement obligations	Asset retirement obligations	12,702		12,561		Asset retirement obligations	15,089		15,030
Other long-term liabilities	Other long-term liabilities	5,305		2,752		Other long-term liabilities	3,709		3,606
TOTAL LIABILITIES	TOTAL LIABILITIES	240,420		184,292		TOTAL LIABILITIES	33,436		61,270
COMMITMENTS AND CONTINGENCIES (Note 7)	COMMITMENTS AND CONTINGENCIES (Note 7)	0		0		COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY	MEZZANINE EQUITY					MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2022 and December 31, 2021, respectively		298,361		298,361
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2023 and December 31, 2022, respectively						Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2023 and December 31, 2022, respectively	298,361		298,361
EQUITY	EQUITY					EQUITY
Partners' equity – general partner interest	Partners' equity – general partner interest	—		—		Partners' equity – general partner interest	—		—
Partners' equity – common units, 209,392 and 208,666 units outstanding at March 31, 2022 and December 31, 2021, respectively		699,788		765,268
Partners' equity – common units, 209,963 and 209,407 units outstanding at March 31, 2023 and December 31, 2022, respectively						Partners' equity – common units, 209,963 and 209,407 units outstanding at March 31, 2023 and December 31, 2022, respectively	939,867		911,451
TOTAL EQUITY	TOTAL EQUITY	699,788		765,268		TOTAL EQUITY	939,867		911,451
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,238,569	$	1,247,921	TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,271,664	$	1,271,082

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)


		Three Months Ended March 31,				Three Months Ended March 31,
		2022		2021				2023		2022
REVENUE	REVENUE						REVENUE
Oil and condensate sales	Oil and condensate sales	$	75,831	$	44,176		Oil and condensate sales	$	60,909	$	75,831
Natural gas and natural gas liquids sales	Natural gas and natural gas liquids sales	75,754		42,889			Natural gas and natural gas liquids sales	57,423		75,754
Lease bonus and other income	Lease bonus and other income	4,859		2,385			Lease bonus and other income	3,975		4,859
Revenue from contracts with customers	Revenue from contracts with customers	156,444		89,450			Revenue from contracts with customers	122,307		156,444
Gain (loss) on commodity derivative instruments	Gain (loss) on commodity derivative instruments	(120,020)		(27,882)			Gain (loss) on commodity derivative instruments	52,271		(120,020)
TOTAL REVENUE	TOTAL REVENUE	36,424		61,568			TOTAL REVENUE	174,578		36,424
OPERATING (INCOME) EXPENSE	OPERATING (INCOME) EXPENSE						OPERATING (INCOME) EXPENSE
Lease operating expense	Lease operating expense	3,161		2,664			Lease operating expense	2,668		3,161
Production costs and ad valorem taxes	Production costs and ad valorem taxes	13,949		11,842			Production costs and ad valorem taxes	12,667		13,949
Exploration expense	Exploration expense	180		1,073			Exploration expense	4		180
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	10,917		15,632			Depreciation, depletion, and amortization	11,147		10,917

General and administrative	General and administrative	13,763		12,852			General and administrative	12,648		13,763
Accretion of asset retirement obligations	Accretion of asset retirement obligations	202		292			Accretion of asset retirement obligations	245		202

TOTAL OPERATING EXPENSE	TOTAL OPERATING EXPENSE	42,172		44,355			TOTAL OPERATING EXPENSE	39,379		42,172
INCOME (LOSS) FROM OPERATIONS	INCOME (LOSS) FROM OPERATIONS	(5,748)		17,213			INCOME (LOSS) FROM OPERATIONS	135,199		(5,748)
OTHER INCOME (EXPENSE)	OTHER INCOME (EXPENSE)						OTHER INCOME (EXPENSE)

Interest and investment income							Interest and investment income	157		—
Interest expense	Interest expense	(1,209)		(1,210)			Interest expense	(814)		(1,209)
Other income (expense)	Other income (expense)	(45)		183			Other income (expense)	(99)		(45)
TOTAL OTHER EXPENSE	TOTAL OTHER EXPENSE	(1,254)		(1,027)			TOTAL OTHER EXPENSE	(756)		(1,254)
NET INCOME (LOSS)	NET INCOME (LOSS)	(7,002)		16,186			NET INCOME (LOSS)	134,443		(7,002)

Distributions on Series B cumulative convertible preferred units	Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)			Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936		NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	129,193	$	(12,252)
ALLOCATION OF NET INCOME (LOSS):	ALLOCATION OF NET INCOME (LOSS):						ALLOCATION OF NET INCOME (LOSS):
General partner interest	General partner interest	$	—	$	—		General partner interest	$	—	$	—
Common units	Common units	(12,252)		10,936			Common units	129,193		(12,252)
		$	(12,252)	$	10,936			$	129,193	$	(12,252)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:	NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:						NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	Per common unit (basic)	$	(0.06)	$	0.05		Per common unit (basic)	$	0.62	$	(0.06)
Per common unit (diluted)	Per common unit (diluted)	$	(0.06)	$	0.05		Per common unit (diluted)	$	0.60	$	(0.06)
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:	WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:						WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	Weighted average common units outstanding (basic)	209,323		207,442			Weighted average common units outstanding (basic)	209,941		209,323
Weighted average common units outstanding (diluted)	Weighted average common units outstanding (diluted)	209,323		207,442			Weighted average common units outstanding (diluted)	224,910		209,323

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)

Common units Partners' equity — common units Total equity
BALANCE AT DECEMBER 31, 2021 208,666 $ 765,268 $ 765,268
Repurchases of common units (262) (2,991) (2,991)
Restricted units granted, net of forfeitures 988 — —
Equity–based compensation — 6,659 6,659
Distributions — (56,462) (56,462)
Charges to partners' equity for accrued distribution equivalent rights — (434) (434)
Distributions on Series B cumulative convertible preferred units — (5,250) (5,250)
Net income (loss) — (7,002) (7,002)
BALANCE AT MARCH 31, 2022 209,392 $ 699,788 $ 699,788


	Common units	Partners' equity
BALANCE AT DECEMBER 31, 2022	209,407	$	911,451
Repurchases of common units	(358)	(5,496)


Restricted units granted, net of forfeitures	914	—
Equity–based compensation	—	5,052
Distributions	—	(99,600)
Charges to partners' equity for accrued distribution equivalent rights	—	(733)
Distributions on Series B cumulative convertible preferred units	—	(5,250)
Net income (loss)	—	134,443
BALANCE AT MARCH 31, 2023	209,963	$	939,867


		Common units	Partners' equity — common units		Total equity			Common units	Partners' equity
BALANCE AT DECEMBER 31, 2020		206,749	$	760,606	$	760,606
BALANCE AT DECEMBER 31, 2021							BALANCE AT DECEMBER 31, 2021	208,666	$	765,268
Repurchases of common units	Repurchases of common units	(223)	(1,957)		(1,957)		Repurchases of common units	(262)	(2,991)

Restricted units granted, net of forfeitures	Restricted units granted, net of forfeitures	1,016	—		—		Restricted units granted, net of forfeitures	988	—
Equity–based compensation	Equity–based compensation	—	5,353		5,353		Equity–based compensation	—	6,659
Distributions	Distributions	—	(36,272)		(36,272)		Distributions	—	(56,462)
Charges to partners' equity for accrued distribution equivalent rights	Charges to partners' equity for accrued distribution equivalent rights	—	(237)		(237)		Charges to partners' equity for accrued distribution equivalent rights	—	(434)
Distributions on Series B cumulative convertible preferred units	Distributions on Series B cumulative convertible preferred units	—	(5,250)		(5,250)		Distributions on Series B cumulative convertible preferred units	—	(5,250)
Net income (loss)	Net income (loss)	—	16,186		16,186		Net income (loss)	—	(7,002)
BALANCE AT MARCH 31, 2021		207,542	$	738,429	$	738,429
BALANCE AT MARCH 31, 2022							BALANCE AT MARCH 31, 2022	209,392	$	699,788

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021			2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES	CASH FLOWS FROM OPERATING ACTIVITIES					CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	Net income (loss)	$	(7,002)	$	16,186	Net income (loss)	$	134,443	$	(7,002)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	10,917		15,632		Depreciation, depletion, and amortization	11,147		10,917

Accretion of asset retirement obligations	Accretion of asset retirement obligations	202		292		Accretion of asset retirement obligations	245		202
Amortization of deferred charges	Amortization of deferred charges	347		257		Amortization of deferred charges	255		347
(Gain) loss on commodity derivative instruments	(Gain) loss on commodity derivative instruments	120,020		27,882		(Gain) loss on commodity derivative instruments	(52,271)		120,020
Net cash (paid) received on settlement of commodity derivative instruments	Net cash (paid) received on settlement of commodity derivative instruments	(31,244)		(4,523)		Net cash (paid) received on settlement of commodity derivative instruments	13,285		(31,244)
Equity-based compensation	Equity-based compensation	4,551		3,462		Equity-based compensation	2,118		4,551
Exploratory dry hole expense		—		1,049

Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(2,263)		2,620		Accounts receivable	41,588		(2,263)
Prepaid expenses and other current assets	Prepaid expenses and other current assets	90		275		Prepaid expenses and other current assets	(182)		90
Accounts payable, accrued liabilities, and other	Accounts payable, accrued liabilities, and other	(12,975)		(7,341)		Accounts payable, accrued liabilities, and other	(13,333)		(12,975)
Settlement of asset retirement obligations	Settlement of asset retirement obligations	(67)		(105)		Settlement of asset retirement obligations	(140)		(67)
NET CASH PROVIDED BY OPERATING ACTIVITIES	NET CASH PROVIDED BY OPERATING ACTIVITIES	82,576		55,686		NET CASH PROVIDED BY OPERATING ACTIVITIES	137,155		82,576
CASH FLOWS FROM INVESTING ACTIVITIES	CASH FLOWS FROM INVESTING ACTIVITIES					CASH FLOWS FROM INVESTING ACTIVITIES

Additions to oil and natural gas properties	Additions to oil and natural gas properties	(3,658)		(191)		Additions to oil and natural gas properties	(1,932)		(3,658)
Additions to oil and natural gas properties leasehold costs		—		(21)

Purchases of other property and equipment	Purchases of other property and equipment	(31)		(2)		Purchases of other property and equipment	(22)		(31)

Proceeds from farmouts of oil and natural gas properties	Proceeds from farmouts of oil and natural gas properties	3,593		—		Proceeds from farmouts of oil and natural gas properties	—		3,593
NET CASH USED IN INVESTING ACTIVITIES	NET CASH USED IN INVESTING ACTIVITIES	(96)		(214)		NET CASH USED IN INVESTING ACTIVITIES	(1,954)		(96)
CASH FLOWS FROM FINANCING ACTIVITIES	CASH FLOWS FROM FINANCING ACTIVITIES					CASH FLOWS FROM FINANCING ACTIVITIES

Distributions to common unitholders	Distributions to common unitholders	(56,462)		(36,272)		Distributions to common unitholders	(99,600)		(56,462)
Distributions to Series B cumulative convertible preferred unitholders	Distributions to Series B cumulative convertible preferred unitholders	(5,250)		(5,250)		Distributions to Series B cumulative convertible preferred unitholders	(5,250)		(5,250)

Repurchases of common units	Repurchases of common units	(2,991)		(1,957)		Repurchases of common units	(5,496)		(2,991)
Borrowings under credit facility	Borrowings under credit facility	58,000		39,000		Borrowings under credit facility	50,000		58,000
Repayments under credit facility	Repayments under credit facility	(78,000)		(49,000)		Repayments under credit facility	(60,000)		(78,000)

Debt issuance costs and other						Debt issuance costs and other	(12)		—
NET CASH USED IN FINANCING ACTIVITIES	NET CASH USED IN FINANCING ACTIVITIES	(84,703)		(53,479)		NET CASH USED IN FINANCING ACTIVITIES	(120,358)		(84,703)
NET CHANGE IN CASH AND CASH EQUIVALENTS	NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,223)		1,993		NET CHANGE IN CASH AND CASH EQUIVALENTS	14,843		(2,223)
CASH AND CASH EQUIVALENTS – beginning of the period	CASH AND CASH EQUIVALENTS – beginning of the period	8,876		1,796		CASH AND CASH EQUIVALENTS – beginning of the period	4,307		8,876
CASH AND CASH EQUIVALENTS – end of the period	CASH AND CASH EQUIVALENTS – end of the period	$	6,653	$	3,789	CASH AND CASH EQUIVALENTS – end of the period	$	19,150	$	6,653
SUPPLEMENTAL DISCLOSURE	SUPPLEMENTAL DISCLOSURE					SUPPLEMENTAL DISCLOSURE
Interest paid	Interest paid	$	872	$	941	Interest paid	$	588	$	872

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022 ("~~2021~~2022 Annual Report on Form 10-K").

The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, ~~2022~~2023 are not necessarily indicative of the results to be expected for the full year.

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 (loss) and equity.

The unaudited interim 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 unaudited interim 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Significant accounting policies are disclosed in the Partnership’s ~~2021~~2022 Annual Report on Form 10-K. There have been no changes in such policies or the application of such policies during the three months ended March 31, ~~2022.~~2023.

Accounts Receivable

The following table presents information about the Partnership's accounts receivable:


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022

		(in thousands)					(in thousands)
Accounts receivable:	Accounts receivable:					Accounts receivable:
Revenues from contracts with customers	Revenues from contracts with customers	$	94,691	$	93,005	Revenues from contracts with customers	$	87,553	$	129,078
Other	Other	4,772		4,137		Other	6,633		6,619
Total accounts receivable	Total accounts receivable	$	99,463	$	97,142	Total accounts receivable	$	94,186	$	135,697

NOTE 3 - OIL AND NATURAL GAS PROPERTIES

Acquisitions and divestitures

~~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 Partnership had no material acquisition or divestiture activity during 2022 or 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.~~

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 6 - 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.

~~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.three months ended March 31, 2023.

Farmout Agreements

The Partnership has entered into farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly ~~lower~~lowering 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.

~~BLACK STONE MINERALS, L.P. AND SUBSIDIARIES~~

~~NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS~~

San Augustine Farmout

In March 2021, BSM and XTO reached an agreement to partition jointly owned working interests in the Brent Miller development area in San Augustine County. Under the partition agreement, BSM and XTO exchanged working interests in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units.

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.~~County. 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 5five wells to be drilled in the initial program year, which began in the third quarter of 2021, ~~increasing~~ten wells to be drilled in the second and third program years, and, thereafter, a minimum of 12twelve 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In May 2021, the Partnership entered into a new farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). In April 2022, the Partnership amended the Canaan Farmout and entered into a farmout agreement (the "JWM Farmout") with JWM Oil & Gas LLC ("JWM"). These agreements cover all of the Partnership's share of working interests under active development by Aethon in San Augustine County, Texas and continue for a ten year period, unless earlier terminated in accordance with the terms of the agreements. Canaan, Azul, and JWM will each earn a percentage of the Partnership's working interest in wells drilled and operated by Aethon within the contract area subject to the agreements. Canaan, Azul, and JWM 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 overriding royalty interest ("ORRI") before payout and an increased ORRI after payout on all wells drilled under the farmout agreements. As of March 31, ~~2022, 4~~2023, thirteen wells have been spud by Aethon in the contract area subject to the Canaan, Azul, and JWM Farmouts.

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

Brent Miller Area


Farmout Partner	% of Partnership's Working Interest		Maximum % on an 8/8ths basis
Canaan	64.0	%	32.0	%
Azul	20.0	%	10.0	%
JWM	16.0	%	8.0	%
Total	100.0	%	50.0	%

Other Areas


Farmout Partner	% of Partnership's Working Interest		Maximum % on an 8/8ths basis
Canaan	40.0	%	10.0	%
Azul	50.0	%	12.5	%
JWM	10.0	%	2.5	%
Total	100.0	%	25.0	%

~~BLACK STONE MINERALS, L.P. AND SUBSIDIARIES~~

~~NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS~~

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 4four wells to be drilled in the initial program year, which began in the third quarter of 2020, ~~increasing~~ten wells to ~~a minimum of 15 wells per~~be drilled in the second program year, and, beginning with the third program ~~year.~~year, fifteen wells per year beginning thereafter.

In November 2020, the Partnership entered into a new farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal 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 March 31, ~~2022, 10~~2023, twenty-six wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 compares 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.

The Partnership recognized no impairment of oil and natural gas properties for the three months ended March 31, ~~2022~~2023 and ~~2021,~~2022, respectively. See Note 5 - Fair Value Measurements for further discussion.

NOTE 4 - 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 March 31, ~~2022,~~2023, the Partnership’s open derivative 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 the 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 March 31, ~~2022~~2023 and December 31, ~~2021.~~2022. See Note 5 - 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 March 31, ~~2022,~~2023, the Partnership had 6seven counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The tables below summarize the fair values and classifications 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:


			March 31, 2022								March 31, 2023
Classification	Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet		Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet

			(in thousands)								(in thousands)
Assets:	Assets:								Assets:
Current asset	Current asset	Commodity derivative assets	$	—	$	—	$	—	Current asset	Commodity derivative assets	$	69,715	$	(1,348)	$	68,367
Long-term asset	Long-term asset	Deferred charges and other long-term assets	—		—		—		Long-term asset	Deferred charges and other long-term assets	857		(245)		612
Total assets	Total assets		$	—	$	—	$	—	Total assets		$	70,572	$	(1,593)	$	68,979
Liabilities:	Liabilities:								Liabilities:
Current liability	Current liability	Commodity derivative liabilities	$	138,028	$	—	$	138,028	Current liability	Commodity derivative liabilities	$	1,348	$	(1,348)	$	—
Long-term liability	Long-term liability	Commodity derivative liabilities	4,293		—		4,293		Long-term liability	Commodity derivative liabilities	1,297		(245)		1,052
Total liabilities	Total liabilities		$	142,321	$	—	$	142,321	Total liabilities		$	2,645	$	(1,593)	$	1,052


			December 31, 2021								December 31, 2022
Classification	Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet		Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet

			(in thousands)								(in thousands)
Assets:	Assets:								Assets:
Current asset	Current asset	Commodity derivative assets	$	—	$	—	$	—	Current asset	Commodity derivative assets	$	41,648	$	(10,176)	$	31,472
Long-term asset	Long-term asset	Deferred charges and other long-term assets	—		—		—		Long-term asset	Deferred charges and other long-term assets	797		(69)		728
Total assets	Total assets		$	—	$	—	$	—	Total assets		$	42,445	$	(10,245)	$	32,200
Liabilities:	Liabilities:								Liabilities:
Current liability	Current liability	Commodity derivative liabilities	$	51,544	$	—	$	51,544	Current liability	Commodity derivative liabilities	$	13,419	$	(10,176)	$	3,243
Long-term liability	Long-term liability	Commodity derivative liabilities	2,001		—		2,001		Long-term liability	Commodity derivative liabilities	85		(69)		16
Total liabilities	Total liabilities		$	53,545	$	—	$	53,545	Total liabilities		$	13,504	$	(10,245)	$	3,259

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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:


		Three Months Ended March 31,					Three Months Ended March 31,
Derivatives not designated as hedging instruments	Derivatives not designated as hedging instruments	2022		2021				Derivatives not designated as hedging instruments	2023		2022
		(in thousands)				(in thousands)
Beginning fair value of commodity derivative instruments	Beginning fair value of commodity derivative instruments	$	(53,545)	$	(20,017)			Beginning fair value of commodity derivative instruments	$	28,941	$	(53,545)
Gain (loss) on oil derivative instruments	Gain (loss) on oil derivative instruments	(48,842)		(24,854)				Gain (loss) on oil derivative instruments	7,422		(48,842)
Gain (loss) on natural gas derivative instruments	Gain (loss) on natural gas derivative instruments	(71,178)		(3,028)				Gain (loss) on natural gas derivative instruments	44,849		(71,178)
Net cash paid (received) on settlements of oil derivative instruments	Net cash paid (received) on settlements of oil derivative instruments	15,892		4,502				Net cash paid (received) on settlements of oil derivative instruments	1,400		15,892
Net cash paid (received) on settlements of natural gas derivative instruments	Net cash paid (received) on settlements of natural gas derivative instruments	15,352		21				Net cash paid (received) on settlements of natural gas derivative instruments	(14,685)		15,352
Net change in fair value of commodity derivative instruments	Net change in fair value of commodity derivative instruments	(88,776)		(23,359)				Net change in fair value of commodity derivative instruments	38,986		(88,776)
Ending fair value of commodity derivative instruments	Ending fair value of commodity derivative instruments	$	(142,321)	$	(43,376)			Ending fair value of commodity derivative instruments	$	67,927	$	(142,321)

The Partnership had the following open derivative contracts for oil as of March 31, ~~2022:~~2023:


			Weighted Average Price (Per Bbl)			Range (Per Bbl)									Weighted Average Price (Per Bbl)			Range (Per Bbl)
Period and Type of Contract	Period and Type of Contract	Volume (Bbl)			Low			High	Period and Type of Contract			Volume (Bbl)					Low			High
Oil Swap Contracts:	Oil Swap Contracts:												Oil Swap Contracts:
2022
2023											2023
First Quarter	First Quarter	220,000	$	66.47		$	55.29		$	83.91	First Quarter			210,000	$	79.44		$	73.00		$	85.93
Second Quarter	Second Quarter	660,000	66.47			55.29			83.91		Second Quarter			540,000	80.80			73.00			89.50
Third Quarter	Third Quarter	660,000	66.47			55.29			83.91		Third Quarter			540,000	80.80			73.00			89.50
Fourth Quarter	Fourth Quarter	660,000	66.47			55.29			83.91		Fourth Quarter			540,000	80.80			73.00			89.50
2023
2024											2024
First Quarter	First Quarter	180,000	$	80.40		$	78.00		$	82.80	First Quarter			180,000	$	68.28		$	67.00		$	69.00

Second Quarter											Second Quarter			180,000	68.28			67.00			69.00
Third Quarter											Third Quarter			180,000	68.28			67.00			69.00
Fourth Quarter											Fourth Quarter			180,000	68.28			67.00			69.00

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for natural gas as of March 31, ~~2022:~~2023:


			Weighted Average Price (Per MMBtu)			Range (Per MMBtu)									Weighted Average Price (Per MMBtu)			Range (Per MMBtu)
Period and Type of Contract	Period and Type of Contract	Volume (MMBtu)			Low			High	Period and Type of Contract			Volume (MMBtu)					Low			High
Natural Gas Swap Contracts:	Natural Gas Swap Contracts:												Natural Gas Swap Contracts:
2022
2023											2023

Second Quarter	Second Quarter	8,910,000	$	3.12		$	2.80		$	4.30	Second Quarter			8,190,000	$	5.15		$	3.28		$	6.59
Third Quarter	Third Quarter	9,000,000	3.12			2.80			4.30		Third Quarter			8,280,000	5.15			3.28			6.59
Fourth Quarter	Fourth Quarter	9,000,000	3.12			2.80			4.30		Fourth Quarter			8,280,000	5.15			3.28			6.59
2023
2024											2024
First Quarter	First Quarter	2,700,000	$	3.62		$	3.28		$	4.30	First Quarter			5,460,000	$	3.64		$	3.57		$	3.76
Second Quarter	Second Quarter	1,820,000	3.28			3.28			3.29		Second Quarter			5,460,000	3.64			3.57			3.76
Third Quarter	Third Quarter	1,840,000	3.28			3.28			3.29		Third Quarter			5,520,000	3.64			3.57			3.76
Fourth Quarter	Fourth Quarter	1,840,000	3.28			3.28			3.29		Fourth Quarter			5,520,000	3.64			3.57			3.76

The Partnership entered into the following derivative contracts for ~~natural gas~~oil subsequent to March 31, ~~2022:~~2023:


			Weighted Average Price (Per MMBtu)			Range (Per MMBtu)								Weighted Average Price (Per Bbl)			Range (Per Bbl)
Period and Type of Contract	Period and Type of Contract	Volume (MMBtu)			Low			High	Period and Type of Contract			Volume (Bbl)				Low			High
Natural Gas Swap Contracts:
2023
Oil Swap Contracts:											Oil Swap Contracts:
2024											2024
First Quarter	First Quarter	1,800,000	$	5.04		$	5.03		$	5.05	First Quarter		90,000	$	72.82		$	72.82		$	72.82
Second Quarter	Second Quarter	1,820,000	5.04			5.03			5.05		Second Quarter		90,000	72.82			72.82			72.82
Third Quarter	Third Quarter	1,840,000	5.04			5.03			5.05		Third Quarter		90,000	72.82			72.82			72.82
Fourth Quarter	Fourth Quarter	1,840,000	5.04			5.03			5.05		Fourth Quarter		90,000	72.82			72.82			72.82

NOTE 5 - 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, ~~2022~~2023 and December 31, ~~2021~~2022 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 4 - Commodity Derivative Financial Instruments for further discussion.

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 Netting		Total			Fair Value Measurements Using						Effect of Counterparty Netting		Total
		Level 1		Level 2		Level 3						Level 1		Level 2		Level 3

		(in thousands)											(in thousands)
As of March 31, 2022
As of March 31, 2023												As of March 31, 2023
Financial Assets	Financial Assets											Financial Assets
Commodity derivative instruments	Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—	Commodity derivative instruments	$	—	$	70,572	$	—	$	(1,593)	$	68,979
Financial Liabilities	Financial Liabilities											Financial Liabilities
Commodity derivative instruments	Commodity derivative instruments	$	—	$	142,321	$	—	$	—	$	142,321	Commodity derivative instruments	$	—	$	2,645	$	—	$	(1,593)	$	1,052
As of December 31, 2021
As of December 31, 2022												As of December 31, 2022
Financial Assets	Financial Assets											Financial Assets
Commodity derivative instruments	Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—	Commodity derivative instruments	$	—	$	42,445	$	—	$	(10,245)	$	32,200
Financial Liabilities	Financial Liabilities											Financial Liabilities
Commodity derivative instruments	Commodity derivative instruments	$	—	$	53,545	$	—	$	—	$	53,545	Commodity derivative instruments	$	—	$	13,504	$	—	$	(10,245)	$	3,259

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~~Partnership had no business combinations for ~~recent acquisitions are included in~~the three months ended March 31, 2023 or the year ended December 31, 2022. See Note 3 - 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’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty, particularly in the current volatile market, 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 as of March 31, ~~2022~~2023 or December 31, ~~2021.~~2022. There were no assets measured at fair value on a non-recurring basis for the three months ended March 31, 2023 or the year ended December 31, 2022.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 - 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.~~billion. The commitment of the lenders equals the ~~lesser~~least of the aggregate maximum credit amount, the then-effective borrowing base, and the ~~borrowing base.~~aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership 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. The April and October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. In October 2022, the Partnership revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and the Partnership elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October ~~2022.~~2023.

In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR"). Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to ~~an alternative~~a base rate (which is a rate per annum equal to the ~~greatest~~highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds ~~effective rate~~Rate in effect on such day plus 0.50%, ~~or 1-month LIBOR~~and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or ~~LIBOR,~~Adjusted Term SOFR, in each case, plus the applicable margin. As of December 31, ~~2021~~2022 and March 31, ~~2022,~~2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the ~~applicable~~Adjusted Term SOFR margin ~~for LIBOR~~ ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

The weighted-average interest rate of the Credit Facility was ~~2.94%~~6.65% during the quarter ended March 31, 2023 and ~~2.61%~~the weighted-average interest rate was 6.92% as of ~~March 31, 2022 and~~ December 31, ~~2021, respectively.~~2022. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

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 Facility (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 March 31, ~~2022,~~2023, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was ~~$69.0 million~~zero and ~~$89.0~~$10.0 million at March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively. The unused portion of the available borrowings under the Credit Facility were ~~$331.0~~$375.0 million and ~~$311.0~~$365.0 million at March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively.

The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after June 30, 2023. Our Credit Facility uses the 1-month LIBOR setting and 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.

NOTE 7 - 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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.

~~BLACK STONE MINERALS, L.P. AND SUBSIDIARIES~~

~~NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS~~

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 March 31, ~~2022~~2023 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

NOTE 8 - INCENTIVE COMPENSATION

The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented:


		Three Months Ended March 31,				Three Months Ended March 31,
		2022		2021				2023		2022

		(in thousands)						(in thousands)
Cash—short and long-term incentive plans	Cash—short and long-term incentive plans	$	996	$	1,385		Cash—short and long-term incentive plans	$	1,079	$	996
Equity-based compensation—restricted common units	Equity-based compensation—restricted common units	927		949			Equity-based compensation—restricted common units	954		927
Equity-based compensation—restricted performance units	Equity-based compensation—restricted performance units	3,093		2,161			Equity-based compensation—restricted performance units	633		3,093
Board of Directors incentive plan	Board of Directors incentive plan	531		352			Board of Directors incentive plan	531		531
Total incentive compensation expense	Total incentive compensation expense	$	5,547	$	4,847		Total incentive compensation expense	$	3,197	$	5,547

In the first quarter of 2023, the Partnership repurchased 357,761 common units at an average price of $15.36 per unit for the purpose of satisfying tax withholding obligations upon the vesting of certain long-term incentive equity awards held by our executive officers and certain other employees. Specifically, when an employee's equity award vests, the Partnership withholds a portion of the shares to cover the employee's tax liability.

In the first quarter of 2022, the board of directors of the Partnership's general partner (the "Board") approved a grant of awards to all employees dependent on the achievement of an aspirational production target to be measured in the fourth quarter of 2025 (the "Aspirational Awards"). The Aspirational Awards include performance cash awards and performance equity awards in the form of restricted performance units. To the extent earned, each performance unit represents the right to receive one common unit. The performance cash awards and performance units are eligible to become earned at the end of the requisite service period on December 31, 2025 if the minimum performance metrics are achieved. The minimum performance metrics are at least 42 Mboe per day of average daily royalty production in either the fourth quarter or the month of December of 2025 while maintaining a net debt to EBITDA ratio less than or equal to 1.0 on December 31, 2025. Average daily royalty production does not include production attributable to acquisitions consummated during the performance period. Compensation expense related to the Aspirational Awards will be recorded over the service period when achievement of the performance condition is probable. Total compensation expense to be recognized over the life of the Aspirational Awards consists of ~~$4.7~~$5.1 million for the performance cash awards and ~~$16.9~~$14.2 million for the performance equity awards ~~(1,463,202~~(1,212,360 performance units with a weighted-average grant date fair value of ~~$11.55~~$11.72 per unit). As of March 31, ~~2022,~~2023, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

NOTE 9 - 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 for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million.

The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%7.0%, payable on a quarterly basis in ~~arrears.~~ arrears; 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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-distribution rate shall be increased by 2.0% per annum for such quarter.

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 ~~1-for-one~~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 $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.

The Partnership has the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on November 28, 2023 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value. Thereafter, the Partnership may redeem the Series B cumulative convertible preferred units at par within a 90 day period on each second anniversary following November 28, 2023.

The Series B cumulative convertible preferred units had a carrying value of $298.4 million, including accrued distributions of $5.3 million, as of March 31, ~~2022~~2023 and December 31, ~~2021.~~2022. The Series B cumulative convertible preferred units are

~~BLACK STONE MINERALS, L.P. AND SUBSIDIARIES~~

~~NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS~~

classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

NOTE 10 - 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 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021					2023		2022

		(in thousands, except per unit amounts)				(in thousands, except per unit amounts)
NET INCOME (LOSS)	NET INCOME (LOSS)	$	(7,002)	$	16,186			NET INCOME (LOSS)	$	134,443	$	(7,002)

Distributions on Series B cumulative convertible preferred units	Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)				Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936			NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	129,193	$	(12,252)
ALLOCATION OF NET INCOME (LOSS):	ALLOCATION OF NET INCOME (LOSS):							ALLOCATION OF NET INCOME (LOSS):
General partner interest	General partner interest	$	—	$	—			General partner interest	$	—	$	—
Common units	Common units	(12,252)		10,936				Common units	129,193		(12,252)
		$	(12,252)	$	10,936				$	129,193	$	(12,252)
NUMERATOR:								NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders								Numerator for basic EPU - Net income (loss) attributable to common unitholders	$	129,193	$	(12,252)
Effect of dilutive securities								Effect of dilutive securities	5,250		—
Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities								Numerator for diluted EPU - net income (loss) attributable to common unitholders after the effect of dilutive securities	$	134,443	$	(12,252)
DENOMINATOR:								DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)								Denominator for basic EPU - weighted average common units outstanding (basic)	209,941		209,323
Effect of dilutive securities								Effect of dilutive securities	14,969		—
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities								Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities	224,910		209,323
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:	NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:							NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	Per common unit (basic)	$	(0.06)	$	0.05			Per common unit (basic)	$	0.62	$	(0.06)
Per common unit (diluted)	Per common unit (diluted)	$	(0.06)	$	0.05			Per common unit (diluted)	$	0.60	$	(0.06)
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)		209,323		207,442
Effect of dilutive securities		—		—
Weighted average common units outstanding (diluted)		209,323		207,442

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:


		Three Months Ended March 31,			Three Months Ended March 31,
		2022	2021				2023	2022

		(in thousands)		(in thousands)
Potentially dilutive securities (common units):	Potentially dilutive securities (common units):					Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	Series B cumulative convertible preferred units on an as-converted basis	14,969	14,969			Series B cumulative convertible preferred units on an as-converted basis	—	14,969

~~BLACK STONE MINERALS, L.P. AND SUBSIDIARIES~~

~~NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS~~

NOTE 11 - COMMON UNITS

Common Units

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

The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 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 unitholders:
Three Months Ended March 31,
2022 2021
Distributions declared and paid per common unit $ 0.2700 $ 0.1750


	Three Months Ended March 31,
	2023		2022
Distributions declared and paid per common unit	$	0.4750	$	0.2700

~~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 three months ended March 31, 2022. As of March 31, 2022, 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 on the Credit Facility. Any repurchased units are canceled.

NOTE 12 - SUBSEQUENT EVENTS

On April ~~25, 2022,~~19, 2023, the Board approved a distribution for the three months ended March 31, ~~2022~~2023 of ~~$0.40~~$0.475 per common unit. Distributions will be payable on May ~~20, 2022~~19, 2023 to unitholders of record at the close of business on May ~~13, 2022.~~12, 2023.

1617

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022 ("~~2021~~2022 Annual Report on Form 10-K"). This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”

Cautionary Note Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•our ability to execute our business strategies;

•~~the scope and duration of the COVID-19 pandemic and actions taken by governmental authorities and other parties in response to the pandemic;~~

•~~the conflict in Ukraine and actions taken, and may in the future be taken, against Russia or otherwise as a result;~~

•the volatility of realized oil and natural gas prices;

•the level of production on our properties;

•the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;

•~~the availability of U.S. liquefied natural gas ("LNG") export capacity and the level of demand for LNG exports;~~

•our ability to replace our oil and natural gas reserves;

•~~our ability to identify, complete, and integrate acquisitions;~~

•general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;

•competition in the oil and natural gas industry;

•the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;

•the ability of our operators to obtain capital or financing needed for development and exploration operations;

•title defects in the properties in which we invest;

•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

•restrictions on the use of water for hydraulic fracturing;

•the availability of pipeline capacity and transportation facilities;

•the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

•future operating results;

•future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;

•exploration and development drilling prospects, inventories, projects, and programs;

•operating hazards faced by our operators;

•the ability of our operators to keep pace with technological advancements;

•conservation measures and general concern about the environmental impact of the production and use of fossil fuels;

•cybersecurity incidents, including data security breaches or computer viruses; and

•certain factors discussed elsewhere in this filing.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our ~~2021~~2022 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.

Overview

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders.

As of March 31, ~~2022,~~2023, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in over ~~70,000~~68,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Recent Developments

Shelby Trough Development Update

Aethon has successfully turned ~~six~~sixteen wells to sales ~~(four of which came online in April 2022)~~ and has commenced operations on ~~four~~ten additional wells under the development agreement covering Angelina County. Aethon ~~is currently drilling two~~has successfully turned 4 wells to sales and has another ~~two~~nine wells awaiting completion operations under the separate development agreement covering San Augustine County. Additionally, XTO Energy has resumed drilling ~~three wells~~ on our Shelby Trough acreage in San Augustine County ~~that were originally spud in 2019.~~and has one well currently awaiting completion operations.

Austin Chalk Update

We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions. The results of our 2021 three well test program in the Brookeland Field demonstrates that modern completion technology can greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. ~~Four~~Eight operators are actively engaged in redevelopment of the field, with two rigs running continuously in the play. To date, ~~seven~~twenty-two wells with modern completions are now producing in the area, and an additional ~~five~~six are currently either being drilled or completed.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

~~COVID-19 Pandemic and Market Conditions~~

The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. With widespread availability of vaccines, the U.S. Centers for Disease Control and Prevention has revised its guidance, most travel restrictions have been lifted, and many businesses have reopened. We currently offer employees the option to work remotely or, subject to compliance with our health and safety guidelines, in the office.

We do not expect these arrangements to negatively impact our ability to maintain operations. We continue to prioritize the health and safety of our workforce through frequent cleaning of common spaces, appropriate physical distancing measures, and other best practices as recommended by federal, state and local officials.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.

~~The impact of~~Commodity prices decreased from the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand. This, in turn, resulted in periods of significantly lower market pricesprior period ended March 31, 2022, due to several factors, including reduced demand for ~~oil,~~ natural gas and ~~natural~~rising global oil inventories. Natural gas ~~liquids ("NGLs"). Commodity~~ prices have subsequently recovered, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners. In addition, Russia's military incursion into Ukraine and the subsequent sanctions imposed on Russia and other actions created significant market uncertainties about the potential for supply disruptions that further increased global commodity pricesdecreased in the first quarter of ~~2022.~~2023 as a result of reduced consumption due to the early emergence of warmer than expected weather conditions in the first two months of the quarter. The current price environment remains uncertain as responses to ~~the COVID-19 pandemic~~elevated inflation and the conflict in Ukraine continue to evolve. The EIA expects relatively flat U.S. natural gas production, increases in LNG exports, and increased consumption in the electric power sector will raise prices in 2023. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

The following table reflects commodity prices ~~as of~~at the ~~last day~~end of each quarter presented:


		2022		2021			2023			2022
Benchmark Prices1	Benchmark Prices1	First Quarter		First Quarter		Benchmark Prices1		First Quarter			First Quarter
WTI spot oil price ($/Bbl)	WTI spot oil price ($/Bbl)	$	100.53	$	59.19	WTI spot oil price ($/Bbl)		$	75.68		$	100.53
Henry Hub spot natural gas ($/MMBtu)	Henry Hub spot natural gas ($/MMBtu)	5.46		2.52		Henry Hub spot natural gas ($/MMBtu)		2.10			5.46

1 Source: EIA

~~Natural Gas Exports~~

Rising levels of U.S.LNG exports have been a growing source of demand and have positively impacted natural gas prices, particularly in the Gulf Coast region where the majority of our natural gas is produced. LNG prices in Europe remain high amid supply uncertainties due to Russia's further invasion of Ukraine and the need to replenish Europe's natural gas inventories, which has kept Europe's demand for LNG elevated. Net natural gas exports averaged 11.5 Bcf per day in the first quarter of 2022, an 18% increase from the 2021 average. The EIA expects high levels of U.S. LNG exports to continue, forecasting average exports of 12.4 Bcf per day for the rest of 2022 and 12.6 Bcf per day for 2023. The EIA forecast reflects the assumption that global natural gas demand remains strong and that expected additional U.S. LNG export capacity comes online.

Rig Count

As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count ~~as of~~at the ~~last day~~end of each quarter presented:


		2022	2021		2023	2022
U.S. Rotary Rig Count1	U.S. Rotary Rig Count1	First Quarter	First Quarter	U.S. Rotary Rig Count1	First Quarter	First Quarter
Oil	Oil	531	324	Oil	592	531
Natural gas	Natural gas	137	92	Natural gas	160	137
Other	Other	2	1	Other	3	2
Total	Total	670	417	Total	755	670

1 Source: Baker Hughes Incorporated

Natural Gas Storage

A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA estimates that natural gas inventories will conclude the injection season in October ~~2022~~2023 at ~~3.5~~3.8 Tcf, which is ~~4% lower~~6% higher than the previous five-year average.

The following table shows natural gas storage volumes by region ~~as of~~at the ~~last day~~end of each quarter presented:


		2022	2021		2023	2022
Region1	Region1	First Quarter	First Quarter	Region1	First Quarter	First Quarter
East	East	268	307	East	335	268
Midwest	Midwest	317	401	Midwest	421	317
Mountain	Mountain	89	112	Mountain	80	89
Pacific	Pacific	161	194	Pacific	73	161
South Central	South Central	581	749	South Central	921	581
Total	Total	1,416	1,763	Total	1,830	1,416

1 Source: EIA

Natural Gas Exports

The EIA expects an increase in U.S. LNG exports resulting from three major LNG export projects under construction that will come online by the end of 2024. Net natural gas exports averaged 11.6 Bcf per day in the first quarter of 2023, a 10% increase from the 2022 average. The EIA forecasts average exports of 12.2 Bcf per day for the rest of 2023 and 12.7 Bcf per day for 2024. The EIA forecast reflects the assumption that production remains flat and that expected additional U.S. LNG export capacity comes online.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

•volumes of oil and natural gas produced;

•commodity prices including the effect of derivative instruments; and

•Adjusted EBITDA and Distributable cash flow.

Volumes of Oil and Natural Gas Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States.

•Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("WTI"), is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

•Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, ~~2022~~2023 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed, but not required, to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, ~~2022,~~2023, we ~~have~~had hedged ~~92%~~67% and 6%22% of our available oil and condensate hedge volumes for ~~2022~~2023 and ~~2023,~~2024, respectively. As of March 31, ~~2022,~~2023, we ~~have~~had also hedged ~~72%~~64% and ~~16%~~41% of our available natural gas hedge volumes for ~~2022~~2023 and ~~2023,~~2024, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production. We do not enter into derivative instruments for speculative purposes.

Non-GAAP Financial Measures

Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.

Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021					2023		2022

		(in thousands)				(in thousands)
Net income (loss)	Net income (loss)	$	(7,002)	$	16,186			Net income (loss)	$	134,443	$	(7,002)
Adjustments to reconcile to Adjusted EBITDA:	Adjustments to reconcile to Adjusted EBITDA:							Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	10,917		15,632				Depreciation, depletion, and amortization	11,147		10,917

Interest expense	Interest expense	1,209		1,210				Interest expense	814		1,209
Income tax expense (benefit)	Income tax expense (benefit)	103		(157)				Income tax expense (benefit)	147		103
Accretion of asset retirement obligations	Accretion of asset retirement obligations	202		292				Accretion of asset retirement obligations	245		202
Equity–based compensation	Equity–based compensation	4,551		3,462				Equity–based compensation	2,118		4,551
Unrealized (gain) loss on commodity derivative instruments	Unrealized (gain) loss on commodity derivative instruments	88,776		23,359				Unrealized (gain) loss on commodity derivative instruments	(38,986)		88,776

Adjusted EBITDA	Adjusted EBITDA	98,756		59,984				Adjusted EBITDA	109,928		98,756
Adjustments to reconcile to Distributable cash flow:	Adjustments to reconcile to Distributable cash flow:							Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue	Change in deferred revenue	(9)		(9)				Change in deferred revenue	(5)		(9)
Cash interest expense	Cash interest expense	(862)		(953)				Cash interest expense	(559)		(862)
Preferred unit distributions	Preferred unit distributions	(5,250)		(5,250)				Preferred unit distributions	(5,250)		(5,250)
Distributable cash flow	Distributable cash flow	$	92,635	$	53,772			Distributable cash flow	$	104,114	$	92,635

Results of Operations

Three Months Ended March 31, ~~2022~~2023 Compared to Three Months Ended March 31, ~~2021~~2022

The following table shows our production, ~~revenues, pricing,~~revenue, and operating expenses for the periods presented:


		Three Months Ended March 31,									Three Months Ended March 31,
		2022		2021		Variance					2023		2022		Variance

		(Dollars in thousands, except for realized prices)									(Dollars in thousands, except for realized prices)
Production:	Production:									Production:
Oil and condensate (MBbls)	Oil and condensate (MBbls)	831		829		2		0.2	%	Oil and condensate (MBbls)	793		831		(38)		(4.6)	%
Natural gas (MMcf)1	Natural gas (MMcf)1	12,759		14,911		(2,152)		(14.4)	%	Natural gas (MMcf)1	16,452		12,759		3,693		28.9	%
Equivalents (MBoe)	Equivalents (MBoe)	2,958		3,314		(356)		(10.7)	%	Equivalents (MBoe)	3,535		2,958		577		19.5	%
Equivalents/day (MBoe)	Equivalents/day (MBoe)	32.9		36.8		(3.9)		(10.6)	%	Equivalents/day (MBoe)	39.3		32.9		6.4		19.5	%
Realized prices, without derivatives:	Realized prices, without derivatives:									Realized prices, without derivatives:
Oil and condensate ($/Bbl)	Oil and condensate ($/Bbl)	$	91.25	$	53.29	$	37.96	71.2	%	Oil and condensate ($/Bbl)	$	76.81	$	91.25	$	(14.44)	(15.8)	%
Natural gas ($/Mcf)1	Natural gas ($/Mcf)1	5.94		2.88		3.06		106.3	%	Natural gas ($/Mcf)1	3.49		5.94		(2.45)		(41.2)	%
Equivalents ($/Boe)	Equivalents ($/Boe)	$	51.25	$	26.27	$	24.98	95.1	%	Equivalents ($/Boe)	$	33.47	$	51.25	$	(17.78)	(34.7)	%
Revenue:	Revenue:									Revenue:
Oil and condensate sales	Oil and condensate sales	$	75,831	$	44,176	$	31,655	71.7	%	Oil and condensate sales	$	60,909	$	75,831	$	(14,922)	(19.7)	%
Natural gas and natural gas liquids sales1	Natural gas and natural gas liquids sales1	75,754		42,889		32,865		76.6	%	Natural gas and natural gas liquids sales1	57,423		75,754		(18,331)		(24.2)	%
Lease bonus and other income	Lease bonus and other income	4,859		2,385		2,474		103.7	%	Lease bonus and other income	3,975		4,859		(884)		(18.2)	%
Revenue from contracts with customers	Revenue from contracts with customers	156,444		89,450		66,994		74.9	%	Revenue from contracts with customers	122,307		156,444		(34,137)		(21.8)	%
Gain (loss) on commodity derivative instruments	Gain (loss) on commodity derivative instruments	(120,020)		(27,882)		(92,138)		330.5	%	Gain (loss) on commodity derivative instruments	52,271		(120,020)		172,291		(143.6)	%
Total revenue	Total revenue	$	36,424	$	61,568	$	(25,144)	(40.8)	%	Total revenue	$	174,578	$	36,424	$	138,154	379.3	%
Operating expenses:	Operating expenses:									Operating expenses:
Lease operating expense	Lease operating expense	$	3,161	$	2,664	$	497	18.7	%	Lease operating expense	$	2,668	$	3,161	$	(493)	(15.6)	%
Production costs and ad valorem taxes	Production costs and ad valorem taxes	13,949		11,842		2,107		17.8	%	Production costs and ad valorem taxes	12,667		13,949		(1,282)		(9.2)	%
Exploration expense	Exploration expense	180		1,073		(893)		(83.2)	%	Exploration expense	4		180		(176)		(97.8)	%
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	10,917		15,632		(4,715)		(30.2)	%	Depreciation, depletion, and amortization	11,147		10,917		230		2.1	%

General and administrative	General and administrative	13,763		12,852		911		7.1	%	General and administrative	12,648		13,763		(1,115)		(8.1)	%
Other expense:	Other expense:									Other expense:
Interest expense	Interest expense	1,209		1,210		(1)		(0.1)	%	Interest expense	814		1,209		(395)		(32.7)	%

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Revenue

Total revenue for the quarter ended March 31, ~~2022 decreased~~2023 increased compared to the quarter ended March 31, ~~2021.~~2022. The ~~decrease~~increase in total revenue from the corresponding period is primarily due to ~~an increase in unrealized losses~~a gain from our commodity derivative instruments compared to a loss in the prior period and was partially offset by ~~an increase~~a decrease in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income.

Oil and condensate sales. Oil and condensate sales ~~increased~~decreased for the quarter ended March 31, ~~2022~~2023 as compared to the corresponding period in ~~2021~~2022 primarily due to ~~higher~~lower realized commodity prices ~~while~~and production ~~volumes remained flat.~~volumes. Our mineral and royalty interest oil and condensate volumes accounted for ~~94%~~92% and ~~92%~~94% of total oil and condensate volumes for quarters ended March 31, ~~2022~~2023 and ~~2021,~~2022, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales ~~increased~~decreased for the quarter ended March 31, ~~2022~~2023 as compared to the corresponding prior period. The ~~increase~~decrease was primarily due to ~~higher~~lower realized commodity prices between the comparative periods partially offset by ~~lower~~higher production volumes due to the timing of new development. The ~~decrease~~increase in natural gas and NGL production was primarily driven by ~~the natural decline in producing wells~~new development in the ~~Shelby Trough outpacing new activity from the Aethon development program, which has not yet fully ramped up.~~Haynesville/Bossier play trend. Mineral and royalty interest production accounted for ~~89%~~94% and ~~82%~~89% of our natural gas volumes for the quarters ended March 31, ~~2022~~2023 and ~~2021,~~2022, respectively.

Gain (loss) on commodity derivative instruments. During the first quarter of ~~2022,~~2023, we recognized ~~an increase in losses~~a gain from our commodity derivative instruments compared to a loss in the same period in ~~2021.~~2022. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. For the three months ended March 31, ~~2022,~~2023, we recognized $13.3 million of realized gains and $39.0 million of unrealized gains from our oil and natural gas commodity contracts, compared to $31.2 million of realized losses and $88.8 million of unrealized losses ~~from our oil and natural gas commodity contracts, compared to $4.5 million of realized losses and $23.4 million of unrealized losses~~ in the same period in ~~2021.~~2022. The unrealized ~~losses~~gains on our commodity contracts during the first quarter of 2023 were primarily driven by changes in the forward commodity price curves for natural gas. The unrealized losses for the same period in 2022 were primarily driven by changes in the forward commodity price curves for oil and natural gas. ~~The unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil.~~

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of ~~2022~~2023 was ~~higher~~lower than the same period in ~~2021.~~2022. Leasing activity in the Haynesville/Bossier and Wolfcamp ~~play~~plays made up the majority of lease bonus and other income for the first quarter of ~~2022,~~2023, while a substantial portion of the first quarter ~~2021~~2022 activity came from leasing activity in the ~~Austin Chalk~~Wolfcamp play.

Operating Expenses

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense ~~increased~~decreased for the quarter ended March 31, ~~2022~~2023 as compared to the same period in ~~2021,~~2022, primarily due to ~~higher~~lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended March 31, ~~2022,~~2023, production costs and ad valorem taxes ~~increased~~decreased as compared to the quarter ended March 31, ~~2021,~~2022, primarily due to ~~higher~~lower production taxes stemming from ~~rising~~falling commodity prices partially offset by ~~lower~~higher ad valorem tax estimates.

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense was minimal for the quarter ended March 31, ~~2022~~2023 and in the corresponding prior period in ~~2021.~~2022.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization ~~decreased~~increased for the quarter ended March 31, ~~2022~~2023 as compared to the same period in ~~2021,~~2022, primarily due to increased production partially offset by a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities. The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, ~~2022,~~2023, general and administrative expenses ~~increased~~decreased slightly as compared to the same period in ~~2021,~~2022, primarily due to a ~~$1.1~~$2.4 million decrease in equity compensation offset by a $1.7 million increase in ~~equity~~cash compensation. The ~~increase~~decrease in equity incentive compensation was due to ~~higher~~lower costs recognized for performance-based incentive awards due to ~~upward~~downward movements in our common unit price period over period.

Interest expense. ~~The change in interest~~Interest expense was ~~minimal~~lower in the first quarter of ~~2022~~2023 relative to the corresponding period in ~~2021,~~2022, due to lower average outstanding borrowings under our Credit Facility ~~almost completely~~and partially offset by higher interest rates.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties. As of March 31, ~~2022, we had~~2023, no balance was outstanding ~~borrowings of $69.0 million~~ under the Credit Facility. We have the option to redeem Series B cumulative convertible preferred units beginning on November 28, 2023 . See Note 9 to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

The Board has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions on our common units quarterly or on any other basis, and there is no guarantee that we will pay distributions to our common unitholders in any quarter. The Board may change the foregoing distribution policy at any time and from time to time.

We intend to finance ~~our~~any future acquisitions with cash generated from operations, borrowings from our Credit Facility, proceeds from any future issuances of equity and debt, and proceeds from asset sales. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

Cash Flows

The following table shows our cash flows for the periods presented:


		Three Months Ended March 31,							Three Months Ended March 31,
		2022		2021		Change			2023		2022		Change

		(in thousands)							(in thousands)
Cash flows provided by operating activities	Cash flows provided by operating activities	$	82,576	$	55,686	$	26,890	Cash flows provided by operating activities	$	137,155	$	82,576	$	54,579
Cash flows provided by (used in) investing activities		(96)		(214)		118
Cash flows used in investing activities								Cash flows used in investing activities	(1,954)		(96)		(1,858)
Cash flows used in financing activities	Cash flows used in financing activities	(84,703)		(53,479)		(31,224)		Cash flows used in financing activities	(120,358)		(84,703)		(35,655)

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities increased for the three months ended March 31, ~~2022~~2023 as compared to the same period of ~~2021.~~2022. The increase was primarily due to higher ~~oil and condensate sales and natural gas and NGL sales due~~cash settlements received on our commodity derivative instruments as compared to ~~higher realized commodity prices~~cash settlements paid in ~~the three months ended March 31, 2022 compared to~~ the same period of ~~2021. The overall increase was partially offset by higher cash settlements paid on our commodity derivative instruments.~~2022.

Investing Activities. Net cash used in investing activities in the three months ended March 31, ~~2022 decreased~~2023 increased as compared to the same period of ~~2021.~~2022. The ~~decrease~~increase was primarily due to increased cash ~~received from the farmout of~~additions to oil and natural gas properties, net of farmout reimbursements in the three months ended March 31, ~~2022~~2023 as compared to ~~no cash received from~~ the ~~farmout of oil and natural gas properties in the same period of 2021.~~corresponding prior period.

Financing Activities. Cash flows used in financing activities increased for the three months ended March 31, ~~2022~~2023 as compared to the same period of ~~2021.~~2022. The increase was primarily due to higher distributions to unitholders ~~and additional repayments on our line of credit~~ in the three months ended March 31, ~~2022~~2023 as compared to the corresponding prior period.

Development Capital Expenditures

Our ~~2022~~2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately ~~$4.5~~$7.9 million, net of farmout reimbursements, of which ~~$0.1~~$1.9 million has been invested in the three months ended March 31, ~~2022.~~2023. The majority of this capital is anticipated to be spent for workovers and recompletions on existing wells in which we own a working interest.

Credit Facility

~~Pursuant to our $1.0 billion~~We maintain a senior secured revolving credit agreement, as amended, (the ~~“Credit Facility”~~"Credit Facility")~~, the~~. The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the lenders equals the ~~lesser~~least of the aggregate maximum credit ~~amounts of~~amount, the ~~lenders~~then-effective borrowing base, and the ~~borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties.~~aggregate elected commitment, as it may be adjusted from time to time. Borrowings under the Credit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our Credit Facility terminates on ~~November 1, 2024.~~October 31, 2027. As of March 31, ~~2022, we had~~2023, no balance was outstanding ~~borrowings of $69.0 million at a weighted-average interest rate of 2.94%.~~under the Credit Facility.

The borrowing base is redetermined semi-annually, ~~typically~~usually in April and October ~~of each year, by~~and is derived from the ~~administrative agent, taking into consideration the estimated loan~~ value of our oil and natural gas properties ~~consistent with~~as determined by the administrative agent’s normal lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds oflender syndicate using pricing assumptions that often differ from the ~~lenders to maintain or decrease our existing borrowing base. In addition, we~~current market for future prices. We 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. We also have 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 November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million.~~ The April and October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and we elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million.The next semi-annual redetermination is scheduled for October ~~2022.~~2023.

In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR"). Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to ~~an alternative~~a base rate (which is a rate per annum equal to the ~~greatest~~highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds ~~effective rate~~Rate in effect on such day plus 0.50%, ~~or 1-month LIBOR~~and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or ~~LIBOR,~~Adjusted Term SOFR, in each case, plus the applicable margin. As of December 31, ~~2021~~2022 and March 31, ~~2022,~~2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the ~~applicable~~Adjusted Term SOFR margin ~~for LIBOR~~ ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary ~~LIBOR~~SOFR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. Our Credit Facility is secured by substantially all of our oil and natural gas production and assets.

Our credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain derivative agreements, as well as require the maintenance of certain financial ratios. The credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater as defined in the credit agreement. 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. The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of March 31, ~~2022,~~2023, we were in compliance with all debt covenants.

Contractual Obligations

As of March 31, ~~2022,~~2023, there have been no material changes to our contractual obligations previously disclosed in our ~~2021~~2022 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of March 31, ~~2022,~~2023, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our ~~2021~~2022 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is the pricing of oil, natural gas, and NGLs produced by our operators. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and NGLs have been historically volatile, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash based on a designated floating price. The designated floating price is based on the NYMEX benchmark for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change. See Note 4 - Commodity Derivative Financial Instruments and Note 5 - Fair Value Measurements to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Commodity prices have been historically volatile based upon the dynamics of supply and demand. To estimate the effect lower prices would have on our reserves, we reduced the SEC commodity pricing for the three months ended March 31, ~~2022~~2023 by 10%. This results in an approximate 1% reduction of proved reserve volumes as compared to the unadjusted March 31, ~~2022~~2023 SEC pricing scenario.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, ~~2022,~~2023, we had ~~six~~seven counterparties, all of which were rated Baa1 or better by Moody’s and are lenders under our Credit Facility.

Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. ~~As of~~During the three months ended March 31, ~~2022,~~2023, we had ~~$69.0~~$12.2 million ofaverage outstanding borrowings under our Credit Facility, bearing interest at a ~~weighted-average~~weighted average interest rate of ~~2.94%~~6.65%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of ~~$0.2~~less than $0.1 million for the three months ended March 31, ~~2022,~~2023, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. 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 March 31, ~~2022~~2023 to provide reasonable assurance.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, ~~2022~~2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our ~~2021~~2022 Annual Report on Form 10-K. Except to the extent updated below, there has been no material change in our risk factors from those described in our ~~2021~~2022 Annual Report on Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth our purchases of our common units for each month during the three months ended March 31, ~~2022:~~2023:


Purchases of Common Units	Purchases of Common Units							Purchases of Common Units
Period	Period	Total Number of Common Units Purchased1	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs2		Period	Total Number of Common Units Purchased1	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs2
January 1 - January 31, 2022		101,081	$	11.17	—	$	70,819,075
February 1 - February 28, 2022		160,439	11.61		—	70,819,075
January 1 - January 31, 2023								January 1 - January 31, 2023	118,942	$	15.47	—	$	70,819,075
February 1 - February 28, 2023								February 1 - February 28, 2023	158,263	15.56		—	70,819,075
March 1 - March 31, 2023								March 1 - March 31, 2023	80,556	14.83		—	70,819,075

1 Consists of units withheld to satisfy tax withholding obligations upon the vesting of certain ~~restricted common units~~long-term incentive equity awards held by our executive officers and certain other employees.

2 On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion.

Item 5. Other Information

None.

Item 6. Exhibits



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						Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Mineral 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 November 29, 2017 (SEC File No. 001-37362)).

10.1*						~~LTI Form~~Separation Agreement and General Release of ~~LTI Award Grant Notice~~Claims, dated as of March 2, 2023, by and ~~Award Agreement (Performance Cash Award) under the~~among Jeffrey P. Wood, Black Stone Natural Resources Management Company, and Black Stone Minerals ~~L.P. Long-Term Incentive Plan~~

~~10.2~~*						~~LTI Form~~GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 of ~~LTI Award Grant Notice and Award Agreement (Performance Equity Award) under the~~ Black Stone Minerals, L.P. ~~Long-Term Incentive Plan~~’s Current Report on Form 8-K filed on March 3, 2023).

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

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 Schema Document

101.CAL*						Inline XBRL Calculation Linkbase Document

101.LAB*						Inline XBRL Label Linkbase Document

101.PRE*						Inline XBRL Presentation Linkbase Document

101.DEF*						Inline XBRL Definition Linkbase Document

104*						Cover Page Interactive Data File - the cover page iXBRL tags are embedded within the Inline XBRL document.

* Filed or furnished herewith.

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: May ~~3, 2022~~2, 2023	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		Chief Executive Officer, President, and Chairman
		(Principal Executive Officer)

Date: May ~~3, 2022~~2, 2023	By:	/s/ ~~Jeffrey P. Wood~~Evan M. Kiefer
		~~Jeffrey P. Wood~~Evan M. Kiefer
		~~President and~~Interim Chief Financial Officer and Treasurer
		(Principal Financial Officer)


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statements of Equity	3
	Consolidated Statements of Cash Flows	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1718
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 5.	Other Information	32
Item 6.	Exhibits	33

	Signatures	34