10-Q

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

OR

☐ 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, there were 209,398,324 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

TABLE OF CONTENTS

 

		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	17
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

ii

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
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,653	$	8,876
Accounts receivable	99,463		97,142
Prepaid expenses and other current assets	1,866		1,956
TOTAL CURRENT ASSETS	107,982		107,974
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
Accumulated depreciation, depletion, amortization, and impairment	(1,880,493)		(1,869,731)
Oil and natural gas properties, net	1,123,283		1,131,896
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
NET PROPERTY AND EQUIPMENT	1,124,545		1,133,336
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	6,042		6,611
TOTAL ASSETS	$	1,238,569	$	1,247,921
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,380	$	5,944
Accrued liabilities	5,960		17,589
Commodity derivative liabilities	138,028		51,544
Other current liabilities	2,070		2,063
TOTAL CURRENT LIABILITIES	148,438		77,140
LONG–TERM LIABILITIES
Credit facility	69,000		89,000
Accrued incentive compensation	682		838
Commodity derivative liabilities	4,293		2,001
Asset retirement obligations	12,702		12,561
Other long-term liabilities	5,305		2,752
TOTAL LIABILITIES	240,420		184,292
COMMITMENTS AND CONTINGENCIES (Note 7)
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
EQUITY
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
TOTAL EQUITY	699,788		765,268
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,238,569	$	1,247,921

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

1

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2022		2021
REVENUE
Oil and condensate sales	$	75,831	$	44,176
Natural gas and natural gas liquids sales	75,754		42,889
Lease bonus and other income	4,859		2,385
Revenue from contracts with customers	156,444		89,450
Gain (loss) on commodity derivative instruments	(120,020)		(27,882)
TOTAL REVENUE	36,424		61,568
OPERATING (INCOME) EXPENSE
Lease operating expense	3,161		2,664
Production costs and ad valorem taxes	13,949		11,842
Exploration expense	180		1,073
Depreciation, depletion, and amortization	10,917		15,632
General and administrative	13,763		12,852
Accretion of asset retirement obligations	202		292
TOTAL OPERATING EXPENSE	42,172		44,355
INCOME (LOSS) FROM OPERATIONS	(5,748)		17,213
OTHER INCOME (EXPENSE)
Interest expense	(1,209)		(1,210)
Other income (expense)	(45)		183
TOTAL OTHER EXPENSE	(1,254)		(1,027)
NET INCOME (LOSS)	(7,002)		16,186
Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	(12,252)		10,936
	$	(12,252)	$	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	(0.06)	$	0.05
Per common unit (diluted)	$	(0.06)	$	0.05
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	209,323		207,442
Weighted average common units outstanding (diluted)	209,323		207,442

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

2

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 — common units		Total equity
BALANCE AT DECEMBER 31, 2020	206,749	$	760,606	$	760,606
Repurchases of common units	(223)	(1,957)		(1,957)
Restricted units granted, net of forfeitures	1,016	—		—
Equity–based compensation	—	5,353		5,353
Distributions	—	(36,272)		(36,272)
Charges to partners' equity for accrued distribution equivalent rights	—	(237)		(237)
Distributions on Series B cumulative convertible preferred units	—	(5,250)		(5,250)
Net income (loss)	—	16,186		16,186
BALANCE AT MARCH 31, 2021	207,542	$	738,429	$	738,429

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

3

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(7,002)	$	16,186
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	10,917		15,632
Accretion of asset retirement obligations	202		292
Amortization of deferred charges	347		257
(Gain) loss on commodity derivative instruments	120,020		27,882
Net cash (paid) received on settlement of commodity derivative instruments	(31,244)		(4,523)
Equity-based compensation	4,551		3,462
Exploratory dry hole expense	—		1,049
Changes in operating assets and liabilities:
Accounts receivable	(2,263)		2,620
Prepaid expenses and other current assets	90		275
Accounts payable, accrued liabilities, and other	(12,975)		(7,341)
Settlement of asset retirement obligations	(67)		(105)
NET CASH PROVIDED BY OPERATING ACTIVITIES	82,576		55,686
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties	(3,658)		(191)
Additions to oil and natural gas properties leasehold costs	—		(21)
Purchases of other property and equipment	(31)		(2)
Proceeds from farmouts of oil and natural gas properties	3,593		—
NET CASH USED IN INVESTING ACTIVITIES	(96)		(214)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to common unitholders	(56,462)		(36,272)
Distributions to Series B cumulative convertible preferred unitholders	(5,250)		(5,250)
Repurchases of common units	(2,991)		(1,957)
Borrowings under credit facility	58,000		39,000
Repayments under credit facility	(78,000)		(49,000)
NET CASH USED IN FINANCING ACTIVITIES	(84,703)		(53,479)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,223)		1,993
CASH AND CASH EQUIVALENTS – beginning of the period	8,876		1,796
CASH AND CASH EQUIVALENTS – end of the period	$	6,653	$	3,789
SUPPLEMENTAL DISCLOSURE
Interest paid	$	872	$	941

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

4

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 ("2021 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 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.

5

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 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.

Accounts Receivable

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

	March 31, 2022		December 31, 2021
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	94,691	$	93,005
Other	4,772		4,137
Total accounts receivable	$	99,463	$	97,142

NOTE 3 - OIL AND NATURAL GAS PROPERTIES    

Acquisitions

Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

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.

Farmout Agreements

The Partnership has entered into farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests.

In 2017, the Partnership entered into farmout arrangements with Canaan Resource Partners ("Canaan") and Pivotal Petroleum Partners ("Pivotal") in the Shelby Trough area of East Texas where the Partnership owns a concentrated, relatively high-interest royalty position. This area was under active development by XTO Energy Inc. ("XTO") in San Augustine County, Texas and BPX Energy in Angelina County, Texas through 2019. These farmout agreements were superseded and replaced by the new farmout agreements discussed below.

6

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. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which began in the third quarter of 2021, increasing to a minimum of twelve wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County discussed below.

In May 2021, the Partnership entered into a new farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). 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, four 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	%

7

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

In November 2020, the Partnership entered into a new farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Pivotal Farmout. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. As of March 31, 2022, ten wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership 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 and 2021, 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, 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 and December 31, 2021. 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, the Partnership had six counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.

8

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
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	138,028	$	—	$	138,028
Long-term liability	Commodity derivative liabilities	4,293		—		4,293
Total liabilities		$	142,321	$	—	$	142,321

		December 31, 2021
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	51,544	$	—	$	51,544
Long-term liability	Commodity derivative liabilities	2,001		—		2,001
Total liabilities		$	53,545	$	—	$	53,545

9

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,
Derivatives not designated as hedging instruments	2022		2021
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(53,545)	$	(20,017)
Gain (loss) on oil derivative instruments	(48,842)		(24,854)
Gain (loss) on natural gas derivative instruments	(71,178)		(3,028)
Net cash paid (received) on settlements of oil derivative instruments	15,892		4,502
Net cash paid (received) on settlements of natural gas derivative instruments	15,352		21
Net change in fair value of commodity derivative instruments	(88,776)		(23,359)
Ending fair value of commodity derivative instruments	$	(142,321)	$	(43,376)

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

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2022
First Quarter	220,000	$	66.47	$	55.29	$	83.91
Second Quarter	660,000	66.47		55.29		83.91
Third Quarter	660,000	66.47		55.29		83.91
Fourth Quarter	660,000	66.47		55.29		83.91
2023
First Quarter	180,000	$	80.40	$	78.00	$	82.80

10

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:

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2022
Second Quarter	8,910,000	$	3.12	$	2.80	$	4.30
Third Quarter	9,000,000	3.12		2.80		4.30
Fourth Quarter	9,000,000	3.12		2.80		4.30
2023
First Quarter	2,700,000	$	3.62	$	3.28	$	4.30
Second Quarter	1,820,000	3.28		3.28		3.29
Third Quarter	1,840,000	3.28		3.28		3.29
Fourth Quarter	1,840,000	3.28		3.28		3.29

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

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

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.

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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 and December 31, 2021 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
	Level 1		Level 2		Level 3
	(in thousands)
As of March 31, 2022
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	142,321	$	—	$	—	$	142,321
As of December 31, 2021
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	53,545	$	—	$	—	$	53,545

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

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 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 or December 31, 2021.

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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. The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for October 2022.

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of December 31, 2021 and March 31, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable 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% and 2.61% as of March 31, 2022 and December 31, 2021, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. Distributions are not permitted if there is a default under the Credit 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, the Partnership was in compliance with all financial covenants in the Credit Facility.

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

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.

13

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 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,
	2022		2021
	(in thousands)
Cash—short and long-term incentive plans	$	996	$	1,385
Equity-based compensation—restricted common units	927		949
Equity-based compensation—restricted performance units	3,093		2,161
Board of Directors incentive plan	531		352
Total incentive compensation expense	$	5,547	$	4,847

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 million for the performance cash awards and $16.9 million for the performance equity awards (1,463,202 performance units with a weighted-average grant date fair value of $11.55 per unit). As of March 31, 2022, 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%, payable on a quarterly basis in arrears. The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 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 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 and December 31, 2021. The Series B cumulative convertible preferred units are

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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.

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

	Three Months Ended March 31,
	2022		2021
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	(7,002)	$	16,186
Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	(12,252)		10,936
	$	(12,252)	$	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	(0.06)	$	0.05
Per common unit (diluted)	$	(0.06)	$	0.05
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,
	2022	2021
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	14,969	14,969

15

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 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

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

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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 ("2021 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;

17

•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 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, 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 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.

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Recent Developments

Shelby Trough Development Update

Aethon has successfully turned six wells to sales (four of which came online in April 2022) and has commenced operations on four additional wells under the development agreement covering Angelina County. Aethon is currently drilling two wells and has another two 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.

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 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 operators are actively engaged in redevelopment of the field, with two rigs running continuously in the play. To date, seven wells with modern completions are now producing in the area, and an additional five 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 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 prices for oil, natural gas, and 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 prices in the first quarter of 2022. The current price environment remains uncertain as responses to the COVID-19 pandemic and the conflict in Ukraine continue to evolve. 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.

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

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

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 the last day of each quarter presented:

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

1 Source: Baker Hughes Incorporated

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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 at 3.5 Tcf, which is 4% lower than the previous five-year average.

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

	2022	2021
Region1	First Quarter	First Quarter
East	268	307
Midwest	317	401
Mountain	89	112
Pacific	161	194
South Central	581	749
Total	1,416	1,763

1 Source: EIA

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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.

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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 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 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, we have hedged 92% and 6% of our available oil and condensate hedge volumes for 2022 and 2023, respectively. As of March 31, 2022, we have also hedged 72% and 16% of our available natural gas hedge volumes for 2022 and 2023, 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.

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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,
	2022		2021
	(in thousands)
Net income (loss)	$	(7,002)	$	16,186
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	10,917		15,632
Interest expense	1,209		1,210
Income tax expense (benefit)	103		(157)
Accretion of asset retirement obligations	202		292
Equity–based compensation	4,551		3,462
Unrealized (gain) loss on commodity derivative instruments	88,776		23,359
Adjusted EBITDA	98,756		59,984
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue	(9)		(9)
Cash interest expense	(862)		(953)
Preferred unit distributions	(5,250)		(5,250)
Distributable cash flow	$	92,635	$	53,772

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Results of Operations

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

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

	Three Months Ended March 31,
	2022		2021		Variance
	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	831		829		2		0.2	%
Natural gas (MMcf)1	12,759		14,911		(2,152)		(14.4)	%
Equivalents (MBoe)	2,958		3,314		(356)		(10.7)	%
Equivalents/day (MBoe)	32.9		36.8		(3.9)		(10.6)	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	91.25	$	53.29	$	37.96	71.2	%
Natural gas ($/Mcf)1	5.94		2.88		3.06		106.3	%
Equivalents ($/Boe)	$	51.25	$	26.27	$	24.98	95.1	%
Revenue:
Oil and condensate sales	$	75,831	$	44,176	$	31,655	71.7	%
Natural gas and natural gas liquids sales1	75,754		42,889		32,865		76.6	%
Lease bonus and other income	4,859		2,385		2,474		103.7	%
Revenue from contracts with customers	156,444		89,450		66,994		74.9	%
Gain (loss) on commodity derivative instruments	(120,020)		(27,882)		(92,138)		330.5	%
Total revenue	$	36,424	$	61,568	$	(25,144)	(40.8)	%
Operating expenses:
Lease operating expense	$	3,161	$	2,664	$	497	18.7	%
Production costs and ad valorem taxes	13,949		11,842		2,107		17.8	%
Exploration expense	180		1,073		(893)		(83.2)	%
Depreciation, depletion, and amortization	10,917		15,632		(4,715)		(30.2)	%
General and administrative	13,763		12,852		911		7.1	%
Other expense:
Interest expense	1,209		1,210		(1)		(0.1)	%

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 compared to the quarter ended March 31, 2021. The decrease in total revenue from the corresponding period is primarily due to an increase in unrealized losses from our commodity derivative instruments and was partially offset by an increase 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 for the quarter ended March 31, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices while production volumes remained flat. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2022 and 2021, respectively.

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

Gain (loss) on commodity derivative instruments. During the first quarter of 2022, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2021. 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, we recognized $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. The unrealized losses on our commodity contracts during the first quarter of 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 was higher than the same period in 2021. Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the first quarter of 2022, while a substantial portion of the first quarter 2021 activity came from leasing activity in the Austin Chalk 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 for the quarter ended March 31, 2022 as compared to the same period in 2021, primarily due to higher 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, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2021, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower 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 and in the corresponding prior period in 2021.

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 for the quarter ended March 31, 2022 as compared to the same period in 2021, primarily due to 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.

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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, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to a $1.1 million increase in equity compensation. The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards due to upward movements in our common unit price period over period.

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

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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 outstanding borrowings of $69.0 million under the Credit Facility.

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 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,
	2022		2021		Change
	(in thousands)
Cash flows provided by operating activities	$	82,576	$	55,686	$	26,890
Cash flows provided by (used in) investing activities	(96)		(214)		118
Cash flows used in financing activities	(84,703)		(53,479)		(31,224)

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 as compared to the same period of 2021. The increase was primarily due to higher oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices 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.

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

Financing Activities. Cash flows used in financing activities increased for the three months ended March 31, 2022 as compared to the same period of 2021. 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 as compared to the corresponding prior period.

Development Capital Expenditures

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

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Credit Facility

Pursuant to our $1.0 billion senior secured revolving credit agreement, as amended (the “Credit Facility”), the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. 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. As of March 31, 2022, we had outstanding borrowings of $69.0 million at a weighted-average interest rate of 2.94%.

The borrowing base is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with 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 of the lenders to maintain or decrease our existing borrowing base. In addition, 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 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 October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for October 2022.

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of December 31, 2021 and March 31, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable 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 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, we were in compliance with all debt covenants.

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.

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Contractual Obligations

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

Critical Accounting Policies and Related Estimates

As of March 31, 2022, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2021 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.

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 by 10%. This results in an approximate 1% reduction of proved reserve volumes as compared to the unadjusted March 31, 2022 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, we had six 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 March 31, 2022, we had $69.0 million of outstanding borrowings under our Credit Facility, bearing interest at a weighted-average interest rate of 2.94%. 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 million for the three months ended March 31, 2022, 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. 

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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 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 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 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 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:

Purchases of Common Units
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

1 Consists of units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units 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.

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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 of LTI Award Grant Notice and Award Agreement (Performance Cash Award) under the Black Stone Minerals, L.P. Long-Term Incentive Plan
10.2*	LTI Form of LTI Award Grant Notice and Award Agreement (Performance Equity Award) under the Black Stone Minerals, L.P. Long-Term Incentive Plan
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.

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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	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		Chief Executive Officer and Chairman
		(Principal Executive Officer)
Date: May 3, 2022	By:	/s/ Jeffrey P. Wood
		Jeffrey P. Wood
		President and Chief Financial Officer
		(Principal Financial Officer)

34

EX-10.1

BLACK STONE MINERALS, L.P.

LONG-TERM INCENTIVE PLAN

LTI AWARD GRANT NOTICE

Pursuant to the terms and conditions of the Black Stone Minerals, L.P. Long-Term Incentive Plan, as amended from time to time (the “Plan”), Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), hereby grants to the individual listed below (“you” or “Employee”) this performance cash award (this “Award”) in the Target Amount set forth below. This Award is subject to the terms and conditions set forth herein as well as the terms and conditions set forth in the LTI Award Agreement attached hereto as Exhibit A (the “Agreement”) and in the Plan, each of which is incorporated herein by reference. Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.

Employee:	[●]
Date of Grant:	[●]
Employer:	Black Stone Natural Resources Management Company or any other entity that may employ Employee after the Date of Grant and which entity is the General Partner, Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), or any of their respective Affiliates.
Target Amount:	$[●] (the “Target Amount”)
Performance Period:	Date of Grant through December 31, 2025
Award Type:	Cash Award granted pursuant to Section 6(e) of the Plan.
Earning of this Award:	Subject to the terms and conditions and except as otherwise provided or set forth herein, in the Agreement and in the Plan, this Award shall become earned in the manner set forth below so long as you remain continuously employed by the Employer from the Date of Grant through the end of the Performance Period. The Target Amount will become earned in the Performance Period if the Performance Goal is achieved. As used herein, the following terms have the meanings set forth below:

US 8648333v.4

“Average Daily Royalty Production” means the higher of:

(i)Royalty Production for the fourth quarter of 2025, divided by 92; and

(ii)Royalty Production for December 2025, divided by 31.

“BOE” means a barrel of oil equivalent that is one barrel (42 US gallons) of crude oil or 6,000 cubic feet of natural gas.

“Daily Royalty Production Target” means 42,000 BOE per day of Average Daily Royalty Production.

“Net Debt to EBITDA Ratio” means, for a given date, the amount of Partnership debt outstanding on that date, reduced by cash and cash equivalents, divided by the 2025 Adjusted EBITDA, as reported in the Partnership’s 2025 financial statements.

“Performance Goal” means

(i)the Daily Royalty Production Target; and

(ii)a Net Debt to EBITDA Ratio less than or equal to 1.0 on December 31, 2025.

“Royalty Production” means total production (expressed in BOE) for the relevant period, as calculated by the Partnership for use in its financial reporting, including prior-period adjustments for the relevant period, but excluding:

(i)Production associated with working interests, other than working interests obtained through reversions under the Partnership’s farmout agreements; and

(ii)Production associated with acquisitions consummated on or after January 1, 2022.

You will be deemed to have accepted this Award on the terms and conditions of the Plan, the Agreement and this LTI Award Grant Notice (this “Grant Notice”) unless you provide written notice to the General Partner within 30 days following the Date of Grant stating that you do not wish to accept this Award. Any such notice must be sent to: Black Stone Minerals GP, L.L.C., 1001 Fannin Street, Suite 2020, Houston, Texas 77002, Attention: Senior Vice President, General Counsel, and Secretary. Upon the General Partner’s receipt of any such notice, this Award granted hereunder will automatically be forfeited and the General Partner, Black Stone Minerals, L.P. and their respective Affiliates will not have any further obligations to you under this Grant Notice or the Agreement.

Unless you provide written notice to the General Partner in the manner described above stating that you do not wish to accept this Award, you will be deemed to have acknowledged that (i) you have reviewed the Agreement, the Plan and this Grant Notice in their entirety and fully understand all provisions of the Agreement, the Plan and this Grant Notice and (ii) you agree to accept as binding, conclusive and final all decisions or interpretations of the Committee regarding any questions or determinations arising under the Agreement, the Plan or this Grant Notice.

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IN WITNESS WHEREOF, the General Partner has caused this Grant Notice to be executed by an officer thereunto duly authorized effective for all purposes as provided above.

BLACK STONE MINERALS GP, L.L.C.

By:

Steve Putman

Senior Vice President, General Counsel, and Secretary

Signature Page to

LTI Award Grant Notice

EXHIBIT A

LTI AWARD AGREEMENT

This LTI Award Agreement (this “Agreement”) is made as of the Date of Grant set forth in the Grant Notice to which this Agreement is attached (the “Date of Grant”) by and between Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), and [●] (“Employee”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Plan or the Grant Notice.

1.Award.  Effective as of the Date of Grant, the General Partner hereby grants to Employee the Target Amount set forth in the Grant Notice on the terms and conditions set forth in the Grant Notice, this Agreement and the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan shall control. To the extent earned, this Award represents the right to receive a cash payment equal to the Target Amount, subject to the terms and conditions set forth in the Grant Notice, this Agreement and the Plan. Unless and until this Award has become earned in the manner set forth in the Grant Notice and this Agreement, Employee will have no right to receive any payments in respect of this Award. Prior to payment of this Award, this Award represents an unsecured obligation of Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), payable only from the general assets of the Partnership.

2.Earning of the Target Amount. 

(a)Following the end of the Performance Period, the Committee will determine whether the Performance Goal has been achieved for the Performance Period. The amount of this Award, if any, that actually becomes earned for the Performance Period will be determined in accordance with the Grant Notice and Section 2(b) (and any portion of the Target Amount that does not become so earned shall be automatically forfeited). In the event of the termination of Employee’s employment prior to the last day of the Performance Period, except as otherwise provided in Section 2(b) below, this Award will terminate automatically without any further action by the General Partner or the Partnership and will be automatically forfeited without further notice.

(b)In the event of a Qualifying Termination (as defined in Section 2(d)) prior to the end of the Performance Period or in the event of a termination of employment occurring as a result of Employee’s Disability or death prior to the end of the Performance Period, then, subject to Employee’s compliance with the release requirement described in Section 2(c), notwithstanding anything to the contrary in the Grant Notice, (i) the Performance Period shall continue to run and (ii) the amount of this Award, if any, that actually becomes earned for the Performance Period will be determined at the end of the Performance Period by multiplying the Target Amount for the Performance Period (if earned based on actual performance through the end of the Performance Period) by a fraction, the numerator of which is the number of days Employee was employed by the Employer during the Performance Period and the denominator of which is the number of days in the Performance Period.

(c)As a condition to the application of the provisions of Section 2(b) (other than in the event of a termination of Employee’s employment due to Employee’s death), Employee must first execute within the time provided to do so (and not revoke in any time provided to do so), a release, in a form acceptable to the General Partner, releasing the Committee, the Employer, the Partnership, the General Partner, their respective Affiliates, and each of the foregoing entities’ respective shareholders, members, partners, officers, managers, directors, fiduciaries, employees, representatives, agents and benefit plans (and fiduciaries of such plans) from any and all claims,

Exhibit A-1

including any and all causes of action arising out of Employee’s employment with the Employer and any of its Affiliates or the termination of such employment, but excluding all claims to payments under the Plan and this Agreement.

(d)As used herein, the following terms have the meanings set forth below:

(i)“Cause” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Cause,” then “Cause” means a determination by two-thirds of the Board that Employee:

(1)willfully and continually failed to substantially perform Employee’s duties to the Partnership and its Affiliates (other than a failure resulting from Employee’s Disability);

(2)willfully engaged in conduct that is demonstrably and materially injurious to the Partnership, the General Partner or any of their respective Affiliates, monetarily or otherwise;

(3)has been convicted of, or has plead guilty or nolo contendere to, a misdemeanor involving moral turpitude or a felony;

(4)has committed an act of fraud, or material embezzlement or material theft, in each case, in the course of Employee’s employment relationship with the Employer or one of its Affiliates, or

(5)has materially breached any obligations of Employee under any written agreement (including any non-compete, non-solicitation or confidentiality covenants) entered into between Employee and the Partnership, the General Partner or any of their respective Affiliates.

Notwithstanding the foregoing, except for a failure, breach or refusal that, by its nature, cannot reasonably be expected to be cured, Employee shall have 30 days following the delivery of written notice by the Employer or one of its Affiliates within which to cure any actions or omissions described in clauses (1), (2), (4) or (5) constituting Cause; providedhowever, that, if the Employer reasonably expects irreparable injury from a delay of 30 days, the Employer or one of its Affiliates may give Employee notice of such shorter period within which to cure as is reasonable under the circumstances, which may include the termination of Employee’s employment without notice and with immediate effect.

(ii)“Disability” means Employee’s incapacity, due to accident, sickness or another circumstance that renders Employee unable to perform the essential functions of Employee’s job function, with reasonable accommodation, for a period of at least 90 consecutive days or 120 days in any 12-month period.

(iii)“Good Reason” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Good Reason,” then “Good Reason” means the occurrence of any of the following events without Employee’s written consent:

Exhibit A-2

(1)a reduction in Employee’s total compensation other than a general reduction in compensation that affects all similarly situated employees in substantially the same proportions;

(2)a relocation of Employee’s principal place of employment by more than 50 miles from the location of Employee’s principal place of employment as of the Date of Grant;

(3)any material breach by the Partnership or the General Partner of any material provision of this Agreement;

(4)a material, adverse change in Employee’s title, authority, duties or responsibilities (other than while Employee has a Disability);

(5)a material adverse change in the reporting structure applicable to Employee; or

(6)following a Change of Control, either (x) a failure of the General Partner or one of its Affiliates to continue in effect any benefit plan or compensation arrangement in which Employee was participating immediately prior to such Change of Control or (y) the taking of any action by the General Partner or one of its Affiliates that adversely affects Employee’s participation in, or materially reduces Employee’s benefits or compensation under, any such benefit plan or compensation arrangement, unless, in the case of either clause (x) or (y), there is substituted a comparable benefit plan or compensation arrangement that is at least economically equivalent to the benefit plan or compensation arrangement being terminated or in which Employee’s participation is being adversely affected or Employee’s benefits or compensation are being materially reduced.

Notwithstanding the foregoing provisions of this definition or any other provision of the Agreement to the contrary, any assertion by Employee of a termination for Good Reason shall not be effective unless all of the following conditions are satisfied: (A) Employee must provide written notice to the General Partner of the existence of the condition(s) providing grounds for termination for Good Reason within 30 days of the initial existence of such grounds; (B) the condition(s) specified in such notice must remain uncorrected for 30 days following the General Partner’s receipt of such written notice; and (C) the date of Employee’s termination of employment must occur within 60 days after the initial existence of the condition(s) specified in such notice.

(iv)“Qualifying Termination” means a termination of Employee’s employment (1) by the Employer without Cause or (2) as a result of Employee’s resignation for Good Reason.

3.Payment of this Award. As soon as administratively practicable following the Committee’s determination of whether the Performance Goal was achieved for the Performance Period, but in no event later than March 15 following the end of such Performance Period, Employee (or Employee’s permitted transferee, if applicable) shall be paid an amount of cash equal to the amount subject to this Award and set out in the Grant Notice that becomes earned based on the achievement of the Performance Goal. The Target Amount, if earned, shall not bear any interest owing to the passage of time. Neither this Section 3 nor any action taken pursuant to or in accordance with this Agreement shall be construed to create a trust or a funded or secured obligation of any kind.

Exhibit A-3

4.Tax Withholding. Upon any taxable event arising in connection with this Award, the General Partner shall have the authority and the right to deduct or withhold (or cause the Employer or one of its Affiliates to deduct or withhold), or to require Employee to remit to the General Partner (or the Employer or one of its Affiliates), an amount sufficient to satisfy all applicable federal, state and local taxes required by law to be withheld with respect to such event. In satisfaction of the foregoing requirement, unless otherwise determined by the Committee, the General Partner or the Employer or one of its Affiliates shall withhold from any cash remuneration (including, if applicable, any amount of cash otherwise payable under this Agreement) then or thereafter payable to Employee an amount equal to the aggregate amount of taxes required to be withheld with respect to such event. Employee acknowledges and agrees that none of the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates have made any representation or warranty as to the tax consequences to Employee as a result of the receipt of this Award, the earning of this Award or the forfeiture of this Award. Employee represents that he or she is in no manner relying on the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates or any of their respective managers, directors, officers, employees or authorized representatives (including, without limitation, attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial representatives) for tax advice or an assessment of such tax consequences. Employee represents that he or she has consulted with any tax consultants that Employee deems advisable in connection with this Award.

5.Non-Transferability.  No portion of this Award nor any interests or right therein shall be (a) sold, pledged, assigned or transferred in any manner during the lifetime of Employee other than by will or the laws of descent and distribution or (b) liable for the debts, contracts or engagements of Employee or his or her successors in interest. Except to the extent expressly permitted by the preceding sentence, any purported sale, pledge, assignment, transfer, attachment or encumbrance of this Award or any interest or right therein shall be null, void and unenforceable against the Partnership, the General Partner, the Employer and their respective Affiliates.

6.No Right to Continued Employment or Awards.

(a)For purposes of this Agreement, Employee shall be considered to be employed by the Employer as long as Employee remains an “Employee” (as such term is defined in the Plan), or an employee of a corporation or other entity (or a parent or subsidiary of such corporation or other entity) assuming or substituting a new award for this Award. Without limiting the scope of the preceding sentence, it is specifically provided that Employee shall be considered to have terminated employment at the time of the termination of the status of the entity or other organization that employs Employee as an “Affiliate” of the General Partner. Nothing in the adoption of the Plan, nor the grant of this Award thereunder pursuant to the Grant Notice and this Agreement, shall confer upon Employee the right to continued employment by, or a continued service relationship with, the Employer or any of its Affiliates, or any other entity, or affect in any way the right of the Employer or any such Affiliate, or any other entity to terminate such employment at any time. Unless otherwise provided in a written employment agreement or by applicable law, Employee’s employment by the Employer, or any such Affiliate, or any other entity shall be on an at-will basis, and the employment relationship may be terminated at any time by either Employee or the Employer, or any such Affiliate, or other entity for any reason whatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of such employment, and the cause of such termination, shall be determined

Exhibit A-4

by the Committee or its delegate, and such determination shall be final, conclusive and binding for all purposes.

(b)The grant of this Award is a one-time Award and does not create any contractual or other right to receive a grant of Awards or benefits in lieu of Awards in the future. Future Awards will be at the sole discretion of the Committee.

7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of Employee, such notices or communications shall be effectively delivered if hand delivered to Employee at Employee’s principal place of employment or if sent by registered or certified mail to Employee at the last address Employee has filed with the Employer. In the case of the Partnership or General Partner, such notices or communications shall be effectively delivered if sent by registered or certified mail to the General Partner at its principal executive offices.

8.Agreement to Furnish Information. Employee agrees to furnish to the General Partner all information requested by the General Partner to enable the General Partner or any of its Affiliates to comply with any reporting or other requirement imposed upon the General Partner or any of its Affiliates by or under any applicable statute or regulation.

9.Entire Agreement; Amendment. This Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to this Award; provided, however, that the terms of this Agreement shall not modify and shall be subject to the terms and conditions of any employment and/or severance agreement between the Partnership, the General Partner, the Employer or any of their respective Affiliates and Employee in effect as of the date a determination is to be made under this Agreement. Without limiting the scope of the preceding sentence, except as provided therein, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. The Committee may, in its sole discretion, amend this Agreement from time to time in any manner that is not inconsistent with the Plan; provided, however, that except as otherwise provided in the Plan or this Agreement, any such amendment that materially reduces the rights of Employee shall be effective only if it is in writing and signed by both Employee and an authorized officer of the General Partner.

10.Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of law principles thereof.

11.Successors and Assigns. The General Partner may assign any of its rights under this Agreement without Employee’s consent. This Agreement will be binding upon and inure to the benefit of the successors and assigns of the General Partner. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement will be binding upon Employee and Employee's beneficiaries, executors, administrators and the person(s) to whom this Award may be transferred by will or the laws of descent or distribution.

12.Clawback. Notwithstanding any provision in this Agreement or the Grant Notice to the contrary, to the extent required by (a) applicable law, including, without limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards and/or (b) any policy that may be adopted or amended by the Board from time to time, all payments in respect of this Award shall be subject to forfeiture, repurchase, recoupment and/or cancellation to the extent necessary to comply with such law(s) and/or policy.

Exhibit A-5

13.Severability. If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of such provision shall not affect the validity or enforceability of any other provision of this Agreement and all other provisions shall remain in full force and effect.

14.Code Section 409A. Neither this Award nor any amounts payable pursuant to this Agreement are intended to constitute or provide for a deferral of compensation that is subject to Section 409A of the Code and the Treasury regulations and other interpretive guidance issued thereunder (collectively, “Section 409A”). Notwithstanding the foregoing, none of the Partnership, the General Partner, the Employer or any of their respective Affiliates makes any representations that the payments provided under this Agreement are exempt from or compliant with Section 409A and in no event shall the Partnership, the General Partner, the Employer or any of their respective Affiliates be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by Employee on account of non-compliance with Section 409A.

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Exhibit A-6

EX-10.2

LTI Award Agreement – Performance Units        

(Aspirational Program)        

BLACK STONE MINERALS, L.P.

LONG-TERM INCENTIVE PLAN

LTI AWARD GRANT NOTICE

Pursuant to the terms and conditions of the Black Stone Minerals, L.P. Long-Term Incentive Plan, as amended from time to time (the “Plan”), Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), hereby grants to the individual listed below (“you” or “Employee”) the number of performance-based Phantom Units (the “Performance Units”) set forth below. This award of Performance Units (this “Award”) is subject to the terms and conditions set forth herein as well as the terms and conditions set forth in the LTI Award Agreement attached hereto as Exhibit A (the “Agreement”) and in the Plan, each of which is incorporated herein by reference. Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.

Employee:	[●]
Date of Grant:	[●]
Employer:	Black Stone Natural Resources Management Company or any other entity that may employ Employee after the Date of Grant and which entity is the General Partner, Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), or any of their respective Affiliates.
Target Performance Units:	[●] Performance Units (the “Target Performance Units”)
Award Type: Performance Period:	Phantom Unit granted pursuant to Section 6(b) of the Plan. Date of Grant through December 31, 2025
Earning of Performance Units:	Subject to the terms and conditions and except as otherwise provided or set forth herein, in the Agreement and in the Plan, the Performance Units shall become earned in the manner set forth below so long as you remain continuously employed by the Employer from the Date of Grant through the end of the Performance Period. The number of Performance Units, if any, that become earned in the Performance Period will be equal to the Target Performance Units if the Performance Goal is achieved. As used herein, the following terms have the meanings set forth below: “Average Daily Royalty Production” means the higher of:

(i)Royalty Production for the fourth quarter of 2025, divided by 92; and

(ii)Royalty Production for December 2025, divided by 31.

“BOE” means a barrel of oil equivalent that is one barrel (42 US gallons) of crude oil or 6,000 cubic feet of natural gas.

“Daily Royalty Production Target” means 42,000 BOE per day of Average Daily Royalty Production.

“Net Debt to EBITDA Ratio” means, for a given date, the amount of Partnership debt outstanding on that date, reduced by cash and cash equivalents, divided by the 2025 Adjusted EBITDA, as reported in the Partnership’s 2025 financial statements.

“Performance Goal” means

(i)the Daily Royalty Production Target; and

(ii)a Net Debt to EBITDA Ratio less than or equal to 1.0 on December 31, 2025.

“Royalty Production” means total production (expressed in BOE) for the relevant period, as calculated by the Partnership for use in its financial reporting, including prior-period adjustments for the relevant period, but excluding:

(i)Production associated with working interests, other than working interests obtained through reversions under the Partnership’s farmout agreements; and

(ii)Production associated with acquisitions consummated on or after January 1, 2022.

y clicking to accept, you agree to be bound by the terms and conditions of the Plan, the Agreement and this LTI Award Grant Notice (this “Grant Notice”). You acknowledge that you have reviewed the Agreement, the Plan and this Grant Notice in their entirety and fully understand all provisions of the Agreement, the Plan and this Grant Notice. You hereby agree to accept as binding, conclusive and final all decisions or interpretations of the Committee regarding any questions or determinations arising under the Agreement, the Plan or this Grant Notice.

In lieu of receiving documents in paper format, you agree, to the fullest extent permitted by applicable law, to accept electronic delivery of any documents that the General Partner or any Affiliate may be required to deliver (including prospectuses, prospectus supplements, grant or award notifications and agreements, account statements, annual and quarterly reports, and all other forms of communications) in connection with this and any other award made or offered by the General Partner. Electronic delivery may be made via the electronic mail system of the General Partner or one of its Affiliates or by reference to a location on an intranet site to which you have access. You hereby consent to any and all procedures the General Partner has established or may establish for an electronic signature system for delivery and acceptance of any such documents.

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You acknowledge and agree that clicking to accept this Award constitutes your electronic signature and is intended to have the same force and effect as your manual signature.

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IN WITNESS WHEREOF, the General Partner has caused this Grant Notice to be executed by an officer thereunto duly authorized effective for all purposes as provided above.

BLACK STONE MINERALS GP, L.L.C.

By:

Steve Putman

Senior Vice President, General Counsel, and Secretary

Signature Page to

LTI Award Grant Notice

EXHIBIT A

LTI AWARD AGREEMENT

This LTI Award Agreement (this “Agreement”) is made as of the Date of Grant set forth in the Grant Notice to which this Agreement is attached (the “Date of Grant”) by and between Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”), and [●] (“Employee”). Capitalized terms used but not specifically defined herein shall have the meanings specified in the Plan or the Grant Notice.

1.Award.  Effective as of the Date of Grant, the General Partner hereby grants to Employee the number of performance-based Phantom Units set forth in the Grant Notice (the “Performance Units”) on the terms and conditions set forth in the Grant Notice, this Agreement and the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan shall control. To the extent earned, each Performance Unit represents the right to receive one Common Unit, subject to the terms and conditions set forth in the Grant Notice, this Agreement and the Plan. Unless and until the Performance Units have become earned in the manner set forth in the Grant Notice and this Agreement, Employee will have no right to receive any Common Units or other payments in respect of the Performance Units. Prior to settlement of this Award, the Performance Units and this Award represent an unsecured obligation of Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), payable only from the general assets of the Partnership.

2.Earning of Performance Units. 

(a)Following the end of the Performance Period, the Committee will determine whether the Performance Goal has been achieved for the Performance Period. The number of Performance Units, if any, that actually become earned for the Performance Period will be determined in accordance with the Grant Notice and Section 2(b) (and any Performance Units that do not become so earned shall be automatically forfeited). Unless and until the Performance Units have become earned and been settled in accordance with Section 3, Employee will have no right to receive any distributions with respect to the Performance Units. In the event of the termination of Employee’s employment prior to the last day of the Performance Period, except as otherwise provided in Section 2(b) below, all the Performance Units (and all rights arising from such Performance Units and from being a holder thereof), will terminate automatically without any further action by the General Partner or the Partnership and will be automatically forfeited without further notice.

(b)In the event of a Qualifying Termination (as defined in Section 2(d)) prior to the end of the Performance Period or in the event of a termination of employment occurring as a result of Employee’s Disability or death prior to the end of the Performance Period, then, subject to Employee’s compliance with the release requirement described in Section 2(c), notwithstanding anything to the contrary in the Grant Notice, (i) the Performance Period shall continue to run and (ii) the number of Performance Units, if any, that actually become earned for the Performance Period will be determined at the end of the Performance Period by multiplying Employee’s Target Performance Units for the Performance Period (if earned based on actual performance through the end of the Performance Period) by a fraction, the numerator of which is the number of days Employee was employed by the Employer during the Performance Period and the denominator of which is the number of days in the Performance Period.

Exhibit A-1

(c)As a condition to the application of the provisions of Section 2(b) (other than in the event of a termination of Employee’s employment due to Employee’s death), Employee must first execute within the time provided to do so (and not revoke in any time provided to do so), a release, in a form acceptable to the General Partner, releasing the Committee, the Employer, the Partnership, the General Partner, their respective Affiliates, and each of the foregoing entities’ respective shareholders, members, partners, officers, managers, directors, fiduciaries, employees, representatives, agents and benefit plans (and fiduciaries of such plans) from any and all claims, including any and all causes of action arising out of Employee’s employment with the Employer and any of its Affiliates or the termination of such employment, but excluding all claims to payments under the Plan and this Agreement.

(d)As used herein, the following terms have the meanings set forth below:

(i)“Cause” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Cause,” then “Cause” means a determination by two-thirds of the Board that Employee:

(1)willfully and continually failed to substantially perform Employee’s duties to the Partnership and its Affiliates (other than a failure resulting from Employee’s Disability);

(2)willfully engaged in conduct that is demonstrably and materially injurious to the Partnership, the General Partner or any of their respective Affiliates, monetarily or otherwise;

(3)has been convicted of, or has plead guilty or nolo contendere to, a misdemeanor involving moral turpitude or a felony;

(4)has committed an act of fraud, or material embezzlement or material theft, in each case, in the course of Employee’s employment relationship with the Employer or one of its Affiliates, or

(5)has materially breached any obligations of Employee under any written agreement (including any non-compete, non-solicitation or confidentiality covenants) entered into between Employee and the Partnership, the General Partner or any of their respective Affiliates.

Notwithstanding the foregoing, except for a failure, breach or refusal that, by its nature, cannot reasonably be expected to be cured, Employee shall have 30 days following the delivery of written notice by the Employer or one of its Affiliates within which to cure any actions or omissions described in clauses (1), (2), (4) or (5) constituting Cause; providedhowever, that, if the Employer reasonably expects irreparable injury from a delay of 30 days, the Employer or one of its Affiliates may give Employee notice of such shorter period within which to cure as is reasonable under the circumstances, which may include the termination of Employee’s employment without notice and with immediate effect.

(ii)“Disability” means Employee’s incapacity, due to accident, sickness or another circumstance that renders Employee unable to perform the essential functions of Employee’s job function, with reasonable accommodation, for a period of at least 90 consecutive days or 120 days in any 12-month period.

Exhibit A-2

(iii)“Good Reason” has the meaning assigned to such term in Employee’s severance agreement with the General Partner or one of its Affiliates; provided, however, that if Employee does not have a severance agreement with the General Partner or one of its Affiliates or if such agreement does not define the term “Good Reason,” then “Good Reason” means the occurrence of any of the following events without Employee’s written consent:

(1)a reduction in Employee’s total compensation other than a general reduction in compensation that affects all similarly situated employees in substantially the same proportions;

(2)a relocation of Employee’s principal place of employment by more than 50 miles from the location of Employee’s principal place of employment as of the Date of Grant;

(3)any material breach by the Partnership or the General Partner of any material provision of this Agreement;

(4)a material, adverse change in Employee’s title, authority, duties or responsibilities (other than while Employee has a Disability);

(5)a material adverse change in the reporting structure applicable to Employee; or

(6)following a Change of Control, either (x) a failure of the General Partner or one of its Affiliates to continue in effect any benefit plan or compensation arrangement in which Employee was participating immediately prior to such Change of Control or (y) the taking of any action by the General Partner or one of its Affiliates that adversely affects Employee’s participation in, or materially reduces Employee’s benefits or compensation under, any such benefit plan or compensation arrangement, unless, in the case of either clause (x) or (y), there is substituted a comparable benefit plan or compensation arrangement that is at least economically equivalent to the benefit plan or compensation arrangement being terminated or in which Employee’s participation is being adversely affected or Employee’s benefits or compensation are being materially reduced.

Notwithstanding the foregoing provisions of this definition or any other provision of the Agreement to the contrary, any assertion by Employee of a termination for Good Reason shall not be effective unless all of the following conditions are satisfied: (A) Employee must provide written notice to the General Partner of the existence of the condition(s) providing grounds for termination for Good Reason within 30 days of the initial existence of such grounds; (B) the condition(s) specified in such notice must remain uncorrected for 30 days following the General Partner’s receipt of such written notice; and (C) the date of Employee’s termination of employment must occur within 60 days after the initial existence of the condition(s) specified in such notice.

(iv)“Qualifying Termination” means a termination of Employee’s employment (1) by the Employer without Cause or (2) as a result of Employee’s resignation for Good Reason.

3.Settlement of Performance Units. As soon as administratively practicable following the Committee’s determination of whether the Performance Goal was achieved for the Performance Period, but in no event later than March 15 following the end of such Performance

Exhibit A-3

Period, Employee (or Employee’s permitted transferee, if applicable) shall be issued a number of Common Units equal to the number of Performance Units subject to this Award and set out in the Grant Notice that become earned based on the achievement of the Performance Goal. Any fractional Performance Unit that becomes earned hereunder will be rounded down to the next whole Performance Unit if it is less than 0.5 and rounded up to the next whole Performance Unit if it is 0.5 or more. No fractional Common Units, nor the cash value of any fractional Common Units, will be issuable or payable to Employee pursuant to this Agreement. All Common Units issued hereunder shall be delivered either by delivering one or more certificates for such Common Units to Employee or by entering such Common Units in book-entry form, as determined by the Committee in its sole discretion. The value of Common Units shall not bear any interest owing to the passage of time. Neither this Section 3 nor any action taken pursuant to or in accordance with this Agreement shall be construed to create a trust or a funded or secured obligation of any kind.

4.Rights as Unitholder.  Neither Employee nor any person claiming under or through Employee shall have any of the rights or privileges of a holder of Common Units in respect of any Common Units that may become deliverable hereunder unless and until certificates representing such Common Units have been issued or recorded in book entry form on the records of the Partnership or its transfer agents or registrars, and delivered in certificate or book entry form to Employee or any person claiming under or through Employee.

5.Tax Withholding. Upon any taxable event arising in connection with the Performance Units, the General Partner shall have the authority and the right to deduct or withhold (or cause the Employer or one of its Affiliates to deduct or withhold), or to require Employee to remit to the General Partner (or the Employer or one of its Affiliates), an amount sufficient to satisfy all applicable federal, state and local taxes required by law to be withheld with respect to such event. In satisfaction of the foregoing requirement, unless otherwise determined by the Committee, the General Partner or the Employer or one of its Affiliates shall withhold from any cash or equity remuneration (including, if applicable, any of the Common Units otherwise deliverable under this Agreement) then or thereafter payable to Employee an amount equal to the aggregate amount of taxes required to be withheld with respect to such event. If such tax obligations are satisfied through the withholding or surrender of Common Units pursuant to this Agreement, the maximum number of Common Units that may be so withheld (or surrendered) shall be the number of Common Units that have an aggregate Fair Market Value on the date of withholding (or surrender) equal to the aggregate amount of taxes required to be withheld, determined based on the greatest withholding rates for federal, state, local and foreign income tax and payroll tax purposes that may be utilized without resulting in adverse accounting, tax or other consequences to the General Partner or any of its Affiliates (other than immaterial administrative, reporting or similar consequences), as determined by the Committee. Employee acknowledges and agrees that none of the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates have made any representation or warranty as to the tax consequences to Employee as a result of the receipt of the Performance Units, the earning of the Performance Units or the forfeiture of any of the Performance Units. Employee represents that he or she is in no manner relying on the Board, the Committee, the General Partner, the Partnership, the Employer or any of their respective Affiliates or any of their respective managers, directors, officers, employees or authorized representatives (including, without limitation, attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial representatives) for tax advice or an assessment of such tax consequences. Employee represents that he or she has consulted with any tax consultants that Employee deems advisable in connection with the Performance Units.

Exhibit A-4

6.Refusal to Transfer; Stop-Transfer Notices.  The Partnership shall not be required (a) to transfer on its books any Common Units that have been sold or otherwise transferred in violation of any of the provisions of this Agreement or (b) to treat as owner of such Common Units or to accord the right to vote or pay distributions to any purchaser or other transferee to whom such Common Units shall have been so transferred.  Employee agrees that, in order to ensure compliance with the restrictions referred to herein, the Partnership or the General Partner may issue appropriate “stop transfer” instructions to its transfer agent, if any, and that, if the Partnership transfers its own securities, it may make appropriate notations to the same effect in its own records.

7.Non-Transferability.  Neither the Performance Units nor any interest or right therein shall be (a) sold, pledged, assigned or transferred in any manner during the lifetime of Employee other than by will or the laws of descent and distribution, unless and until the Common Units underlying the Performance Units have been issued, and all restrictions applicable to such Common Units have lapsed, or (b) liable for the debts, contracts or engagements of Employee or his or her successors in interest. Except to the extent expressly permitted by the preceding sentence, any purported sale, pledge, assignment, transfer, attachment or encumbrance of the Performance Units or any interest or right therein shall be null, void and unenforceable against the Partnership, the General Partner, the Employer and their respective Affiliates.

8.Compliance with Securities Law. Notwithstanding any provision of this Agreement to the contrary, the issuance of Common Units hereunder will be subject to compliance with all applicable requirements of applicable law with respect to such securities and with the requirements of any securities exchange or market system upon which the Common Units may then be listed. No Common Units will be issued hereunder if such issuance would constitute a violation of any applicable law or regulation or the requirements of any securities exchange or market system upon which the Common Units may then be listed. In addition, Common Units will not be issued hereunder unless (a) a registration statement under the Securities Act of 1933, as amended (the “Securities Act”) is in effect at the time of such issuance with respect to the Common Units to be issued or (b) in the opinion of legal counsel to the Partnership, the Common Units to be issued are permitted to be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The inability of the Partnership to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Partnership’s legal counsel to be necessary for the lawful issuance and sale of any Common Units hereunder will relieve the Partnership of any liability in respect of the failure to issue such Common Units as to which such requisite authority has not been obtained. As a condition to any issuance of Common Units hereunder, the General Partner or the Partnership may require Employee to satisfy any requirements that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the General Partner or the Partnership.

9.No Right to Continued Employment or Awards.

(a)For purposes of this Agreement, Employee shall be considered to be employed by the Employer as long as Employee remains an “Employee” (as such term is defined in the Plan), or an employee of a corporation or other entity (or a parent or subsidiary of such corporation or other entity) assuming or substituting a new award for this Award. Without limiting the scope of the preceding sentence, it is specifically provided that Employee shall be considered to have terminated employment at the time of the termination of the status of the entity or other organization that employs Employee as an “Affiliate” of the General Partner. Nothing in the adoption of the Plan, nor the award of the Performance Units thereunder pursuant to the Grant

Exhibit A-5

Notice and this Agreement, shall confer upon Employee the right to continued employment by, or a continued service relationship with, the Employer or any of its Affiliates, or any other entity, or affect in any way the right of the Employer or any such Affiliate, or any other entity to terminate such employment at any time. Unless otherwise provided in a written employment agreement or by applicable law, Employee’s employment by the Employer, or any such Affiliate, or any other entity shall be on an at-will basis, and the employment relationship may be terminated at any time by either Employee or the Employer, or any such Affiliate, or other entity for any reason whatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of such employment, and the cause of such termination, shall be determined by the Committee or its delegate, and such determination shall be final, conclusive and binding for all purposes.

(b)The grant of the Performance Units is a one-time Award and does not create any contractual or other right to receive a grant of Awards or benefits in lieu of Awards in the future. Future Awards will be at the sole discretion of the Committee.

10.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of Employee, such notices or communications shall be effectively delivered if hand delivered to Employee at Employee’s principal place of employment or if sent by registered or certified mail to Employee at the last address Employee has filed with the Employer. In the case of the Partnership or General Partner, such notices or communications shall be effectively delivered if sent by registered or certified mail to the General Partner at its principal executive offices.

11.Agreement to Furnish Information. Employee agrees to furnish to the General Partner all information requested by the General Partner to enable the General Partner or any of its Affiliates to comply with any reporting or other requirement imposed upon the General Partner or any of its Affiliates by or under any applicable statute or regulation.

12.Entire Agreement; Amendment. This Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the Performance Units granted hereunder; provided, however, that the terms of this Agreement shall not modify and shall be subject to the terms and conditions of any employment and/or severance agreement between the Partnership, the General Partner, the Employer or any of their respective Affiliates and Employee in effect as of the date a determination is to be made under this Agreement. Without limiting the scope of the preceding sentence, except as provided therein, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. The Committee may, in its sole discretion, amend this Agreement from time to time in any manner that is not inconsistent with the Plan; provided, however, that except as otherwise provided in the Plan or this Agreement, any such amendment that materially reduces the rights of Employee shall be effective only if it is in writing and signed by both Employee and an authorized officer of the General Partner.

13.Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of law principles thereof.

14.Successors and Assigns. The General Partner may assign any of its rights under this Agreement without Employee’s consent. This Agreement will be binding upon and inure to the benefit of the successors and assigns of the General Partner. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement will be binding upon Employee and

Exhibit A-6

Employee's beneficiaries, executors, administrators and the person(s) to whom the Performance Units may be transferred by will or the laws of descent or distribution.

15.Clawback. Notwithstanding any provision in this Agreement or the Grant Notice to the contrary, to the extent required by (a) applicable law, including, without limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards and/or (b) any policy that may be adopted or amended by the Board from time to time, all Common Units issued hereunder shall be subject to forfeiture, repurchase, recoupment and/or cancellation to the extent necessary to comply with such law(s) and/or policy.

16.Severability. If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of such provision shall not affect the validity or enforceability of any other provision of this Agreement and all other provisions shall remain in full force and effect.

17.Code Section 409A. None of the Performance Units or any amounts payable pursuant to this Agreement are intended to constitute or provide for a deferral of compensation that is subject to Section 409A of the Code and the Treasury regulations and other interpretive guidance issued thereunder (collectively, “Section 409A”). Notwithstanding the foregoing, none of the Partnership, the General Partner, the Employer or any of their respective Affiliates makes any representations that the payments provided under this Agreement are exempt from or compliant with Section 409A and in no event shall the Partnership, the General Partner, the Employer or any of their respective Affiliates be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by Employee on account of non-compliance with Section 409A.

[Remainder of Page Intentionally Blank]

Exhibit A-7

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

pursuant to Rule 13a-14(a) and Rule 15d-14(a)

of the Securities Exchange Act of 1934, as amended

I, Thomas L. Carter, Jr., certify that:

1. I have reviewed this report on Form 10-Q of Black Stone Minerals, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2022	/s/ Thomas L. Carter, Jr.
	Thomas L. Carter, Jr.
	Chief Executive Officer
	Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

pursuant to Rule 13a-14(a) and Rule 15d-14(a)

of the Securities Exchange Act of 1934, as amended

I, Jeffrey P. Wood, certify that:

1. I have reviewed this report on Form 10-Q of Black Stone Minerals, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2022	/s/ Jeffrey P. Wood
	Jeffrey P. Wood
	Chief Financial Officer
	Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

EX-32.1

Exhibit 32.1

Certification of

Chief Executive Officer and Chief Financial Officer

under Section 906 of the

Sarbanes Oxley Act of 2002, 18 U.S.C. § 1350

In connection with the report on Form 10-Q of Black Stone Minerals, L.P. (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Thomas L. Carter, Jr., Chief Executive Officer of the Partnership, and Jeffrey P. Wood, Chief Financial Officer of the Partnership, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 3, 2022	/s/ Thomas L. Carter, Jr.
	Thomas L. Carter, Jr. Chief Executive Officer Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.
Date: May 3, 2022	/s/ Jeffrey P. Wood
	Jeffrey P. Wood Chief Financial Officer Black Stone Minerals GP, L.L.C., the general partner of Black Stone Minerals, L.P.

XML

Cover - shares	3 Months Ended
	Mar. 31, 2022	Apr. 29, 2022
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	001-37362
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-1846692
Entity Address, Address Line One	1001 Fannin Street, Suite 2020
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	445-3200
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	BSM
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Smaller reporting company	false
Emerging growth company	false
Entity shell company	false
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Common units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		209,398,324
Preferred Units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
CURRENT ASSETS
Cash and cash equivalents	$ 6,653	$ 8,876
Accounts receivable	99,463	97,142
Prepaid expenses and other current assets	1,866	1,956
TOTAL CURRENT ASSETS	107,982	107,974
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
Accumulated depreciation, depletion, amortization, and impairment	(1,880,493)	(1,869,731)
Oil and natural gas properties, net	1,123,283	1,131,896
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
NET PROPERTY AND EQUIPMENT	1,124,545	1,133,336
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	6,042	6,611
TOTAL ASSETS	1,238,569	1,247,921
CURRENT LIABILITIES
Accounts payable	2,380	5,944
Accrued liabilities	5,960	17,589
Commodity derivative liabilities	138,028	51,544
Other current liabilities	2,070	2,063
TOTAL CURRENT LIABILITIES	148,438	77,140
LONG–TERM LIABILITIES
Credit facility	69,000	89,000
Accrued incentive compensation	682	838
Commodity derivative liabilities	4,293	2,001
Asset retirement obligations	12,702	12,561
Other long-term liabilities	5,305	2,752
TOTAL LIABILITIES	240,420	184,292
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY
Partners' equity – general partner interest	0	0
TOTAL EQUITY	699,788	765,268
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,238,569	1,247,921
Series B Cumulative Convertible Preferred Units
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
Common units
EQUITY
Partners' equity – common units, 209,392 and 208,666 units outstanding at March 31, 2022 and December 31, 2021, respectively	$ 699,788	$ 765,268

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Unproved properties	$ 937,395	$ 937,395
Accumulated depreciation	$ 13,000	$ 12,931
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common units
Partners' equity - units, outstanding (in shares)	209,392	208,666

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
REVENUE
Revenue from contracts with customers	$ 156,444	$ 89,450
Gain (loss) on commodity derivative instruments	(120,020)	(27,882)
TOTAL REVENUE	36,424	61,568
OPERATING (INCOME) EXPENSE
Lease operating expense	3,161	2,664
Production costs and ad valorem taxes	13,949	11,842
Exploration expense	180	1,073
Depreciation, depletion, and amortization	10,917	15,632
General and administrative	13,763	12,852
Accretion of asset retirement obligations	202	292
TOTAL OPERATING EXPENSE	42,172	44,355
INCOME (LOSS) FROM OPERATIONS	(5,748)	17,213
OTHER INCOME (EXPENSE)
Interest expense	(1,209)	(1,210)
Other income (expense)	(45)	183
TOTAL OTHER EXPENSE	(1,254)	(1,027)
NET INCOME (LOSS)	(7,002)	16,186
Distributions on Series B cumulative convertible preferred units	(5,250)	(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	(12,252)	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	(12,252)	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ (12,252)	$ 10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ (0.06)	$ 0.05
Per common unit (diluted) (in dollars per share)	$ (0.06)	$ 0.05
Weighted average common units outstanding (basic) (in shares)	209,323	207,442
Weighted average common units outstanding (diluted) (in shares)	209,323	207,442
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 75,831	$ 44,176
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	75,754	42,889
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 4,859	$ 2,385

XML

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common units	Partners' equity — common units	Series B cumulative convertible preferred units on an as-converted basis	Series B cumulative convertible preferred units on an as-converted basis Partners' equity — common units
Beginning balance (in shares) at Dec. 31, 2020		206,749
Beginning balance at Dec. 31, 2020	$ 760,606		$ 760,606
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(223)
Repurchases of common units	(1,957)		(1,957)
Restricted units granted, net of forfeitures (in shares)		1,016
Equity–based compensation	5,353		5,353
Distributions	(36,272)		(36,272)
Charges to partners' equity for accrued distribution equivalent rights	(237)		(237)
Distributions on Series B cumulative convertible preferred units				$ (5,250)	$ (5,250)
Net income (loss)	16,186		16,186
Ending balance (in shares) at Mar. 31, 2021		207,542
Ending balance at Mar. 31, 2021	738,429		738,429
Beginning balance (in shares) at Dec. 31, 2021		208,666
Beginning balance at Dec. 31, 2021	765,268		765,268
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(262)
Repurchases of common units	(2,991)		(2,991)
Restricted units granted, net of forfeitures (in shares)		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)
Ending balance (in shares) at Mar. 31, 2022		209,392
Ending balance at Mar. 31, 2022	$ 699,788		$ 699,788

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (7,002)	$ 16,186
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	10,917	15,632
Accretion of asset retirement obligations	202	292
Amortization of deferred charges	347	257
(Gain) loss on commodity derivative instruments	120,020	27,882
Net cash (paid) received on settlement of commodity derivative instruments	(31,244)	(4,523)
Equity-based compensation	4,551	3,462
Exploratory dry hole expense	0	1,049
Changes in operating assets and liabilities:
Accounts receivable	(2,263)	2,620
Prepaid expenses and other current assets	90	275
Accounts payable, accrued liabilities, and other	(12,975)	(7,341)
Settlement of asset retirement obligations	(67)	(105)
NET CASH PROVIDED BY OPERATING ACTIVITIES	82,576	55,686
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties	(3,658)	(191)
Additions to oil and natural gas properties leasehold costs	0	(21)
Purchases of other property and equipment	(31)	(2)
Proceeds from farmouts of oil and natural gas properties	3,593	0
NET CASH USED IN INVESTING ACTIVITIES	(96)	(214)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility	58,000	39,000
Repayments under credit facility	(78,000)	(49,000)
NET CASH USED IN FINANCING ACTIVITIES	(84,703)	(53,479)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,223)	1,993
CASH AND CASH EQUIVALENTS – beginning of the period	8,876	1,796
CASH AND CASH EQUIVALENTS – end of the period	6,653	3,789
SUPPLEMENTAL DISCLOSURE
Interest paid	872	941
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(56,462)	(36,272)
Repurchases of common units	(2,991)	(1,957)
Series B cumulative convertible preferred units on an as-converted basis | Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (5,250)	$ (5,250)

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BUSINESS AND BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BUSINESS AND BASIS OF PRESENTATION

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 ("2021 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 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Significant accounting policies are disclosed in the Partnership’s 2021 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.

Accounts Receivable

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

	March 31, 2022		December 31, 2021
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	94,691	$	93,005
Other	4,772		4,137
Total accounts receivable	$	99,463	$	97,142

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OIL AND NATURAL GAS PROPERTIES

3 Months Ended

Mar. 31, 2022

Extractive Industries [Abstract]

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES    

Acquisitions

Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

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.

Farmout Agreements

The Partnership has entered into farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests.

In 2017, the Partnership entered into farmout arrangements with Canaan Resource Partners ("Canaan") and Pivotal Petroleum Partners ("Pivotal") in the Shelby Trough area of East Texas where the Partnership owns a concentrated, relatively high-interest royalty position. This area was under active development by XTO Energy Inc. ("XTO") in San Augustine County, Texas and BPX Energy in Angelina County, Texas through 2019. These farmout agreements were superseded and replaced by the new farmout agreements discussed below.

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. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which began in the third quarter of 2021, increasing to a minimum of twelve wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County discussed below.

In May 2021, the Partnership entered into a new farmout agreement (the "Canaan Farmout") with Canaan and in December 2021, the Partnership entered into a farmout agreement (the "Azul Farmout") with Azul-SA, LLC ("Azul"). 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, four 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	%

Angelina Farmout

In May 2020, the Partnership entered into a development agreement with Aethon to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of fifteen wells per year beginning with the third program year.

In November 2020, the Partnership entered into a new farmout agreement (the "Pivotal Farmout") with Pivotal. The Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon within the contract area subject to the agreement. Pivotal is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Pivotal Farmout. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. As of March 31, 2022, ten wells have been spud by Aethon in the contract area subject to the Pivotal Farmout.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership 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 and 2021, respectively. See Note 5 - Fair Value Measurements for further discussion.

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

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

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
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	138,028	$	—	$	138,028
Long-term liability	Commodity derivative liabilities	4,293		—		4,293
Total liabilities		$	142,321	$	—	$	142,321

		December 31, 2021
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	51,544	$	—	$	51,544
Long-term liability	Commodity derivative liabilities	2,001		—		2,001
Total liabilities		$	53,545	$	—	$	53,545

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,
Derivatives not designated as hedging instruments	2022		2021
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(53,545)	$	(20,017)
Gain (loss) on oil derivative instruments	(48,842)		(24,854)
Gain (loss) on natural gas derivative instruments	(71,178)		(3,028)
Net cash paid (received) on settlements of oil derivative instruments	15,892		4,502
Net cash paid (received) on settlements of natural gas derivative instruments	15,352		21
Net change in fair value of commodity derivative instruments	(88,776)		(23,359)
Ending fair value of commodity derivative instruments	$	(142,321)	$	(43,376)

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

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2022
First Quarter	220,000	$	66.47	$	55.29	$	83.91
Second Quarter	660,000	66.47		55.29		83.91
Third Quarter	660,000	66.47		55.29		83.91
Fourth Quarter	660,000	66.47		55.29		83.91
2023
First Quarter	180,000	$	80.40	$	78.00	$	82.80

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

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2022
Second Quarter	8,910,000	$	3.12	$	2.80	$	4.30
Third Quarter	9,000,000	3.12		2.80		4.30
Fourth Quarter	9,000,000	3.12		2.80		4.30
2023
First Quarter	2,700,000	$	3.62	$	3.28	$	4.30
Second Quarter	1,820,000	3.28		3.28		3.29
Third Quarter	1,840,000	3.28		3.28		3.29
Fourth Quarter	1,840,000	3.28		3.28		3.29

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

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

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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.

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 and December 31, 2021 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
	Level 1		Level 2		Level 3
	(in thousands)
As of March 31, 2022
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	142,321	$	—	$	—	$	142,321
As of December 31, 2021
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	53,545	$	—	$	—	$	53,545

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

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 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 or December 31, 2021.

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CREDIT FACILITY

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

CREDIT FACILITY

CREDIT FACILITY

The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on November 1, 2024. The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for October 2022.

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of December 31, 2021 and March 31, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable 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% and 2.61% as of March 31, 2022 and December 31, 2021, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. Distributions are not permitted if there is a default under the Credit 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, the Partnership was in compliance with all financial covenants in the Credit Facility.

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

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Environmental Matters

The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been recorded.

LitigationFrom 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 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

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INCENTIVE COMPENSATION

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

INCENTIVE COMPENSATION

INCENTIVE COMPENSATIONThe 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,
	2022		2021
	(in thousands)
Cash—short and long-term incentive plans	$	996	$	1,385
Equity-based compensation—restricted common units	927		949
Equity-based compensation—restricted performance units	3,093		2,161
Board of Directors incentive plan	531		352
Total incentive compensation expense	$	5,547	$	4,847

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 million for the performance cash awards and $16.9 million for the performance equity awards (1,463,202 performance units with a weighted-average grant date fair value of $11.55 per unit). As of March 31, 2022, the Partnership determined achievement of the performance condition was not yet probable and no expense was recognized.

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PREFERRED UNITS

3 Months Ended

Mar. 31, 2022

Equity [Abstract]

PREFERRED UNITS

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%, payable on a quarterly basis in arrears. The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 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 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 and December 31, 2021. The Series B cumulative convertible preferred units are

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

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EARNINGS PER UNIT

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

EARNINGS PER UNIT

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.

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

	Three Months Ended March 31,
	2022		2021
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	(7,002)	$	16,186
Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	(12,252)		10,936
	$	(12,252)	$	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	(0.06)	$	0.05
Per common unit (diluted)	$	(0.06)	$	0.05
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,
	2022	2021
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	14,969	14,969

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COMMON UNITS

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

COMMON UNITS

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 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

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.

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SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2022
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS    On April 25, 2022, the Board approved a distribution for the three months ended March 31, 2022 of $0.40 per common unit. Distributions will be payable on May 20, 2022 to unitholders of record at the close of business on May 13, 2022.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Basis of Presentation

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 ("2021 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 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

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.

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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Tables)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Schedule of Accounts Receivable

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

	March 31, 2022		December 31, 2021
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	94,691	$	93,005
Other	4,772		4,137
Total accounts receivable	$	99,463	$	97,142

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OIL AND NATURAL GAS PROPERTIES (Tables)

3 Months Ended

Mar. 31, 2022

Extractive Industries [Abstract]

Business Combination, Segment Allocation

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	%

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Fair Value and Classification of Derivative Instruments

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
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	138,028	$	—	$	138,028
Long-term liability	Commodity derivative liabilities	4,293		—		4,293
Total liabilities		$	142,321	$	—	$	142,321

		December 31, 2021
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	—	$	—	$	—
Long-term asset	Deferred charges and other long-term assets	—		—		—
Total assets		$	—	$	—	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	51,544	$	—	$	51,544
Long-term liability	Commodity derivative liabilities	2,001		—		2,001
Total liabilities		$	53,545	$	—	$	53,545

Changes in Fair Value of Company's Commodity Derivative Instruments

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,
Derivatives not designated as hedging instruments	2022		2021
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(53,545)	$	(20,017)
Gain (loss) on oil derivative instruments	(48,842)		(24,854)
Gain (loss) on natural gas derivative instruments	(71,178)		(3,028)
Net cash paid (received) on settlements of oil derivative instruments	15,892		4,502
Net cash paid (received) on settlements of natural gas derivative instruments	15,352		21
Net change in fair value of commodity derivative instruments	(88,776)		(23,359)
Ending fair value of commodity derivative instruments	$	(142,321)	$	(43,376)

Summary of Open Derivative Contracts

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

		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2022
First Quarter	220,000	$	66.47	$	55.29	$	83.91
Second Quarter	660,000	66.47		55.29		83.91
Third Quarter	660,000	66.47		55.29		83.91
Fourth Quarter	660,000	66.47		55.29		83.91
2023
First Quarter	180,000	$	80.40	$	78.00	$	82.80

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

		Weighted Average Price (Per MMBtu)		Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)			Low		High
Natural Gas Swap Contracts:
2022
Second Quarter	8,910,000	$	3.12	$	2.80	$	4.30
Third Quarter	9,000,000	3.12		2.80		4.30
Fourth Quarter	9,000,000	3.12		2.80		4.30
2023
First Quarter	2,700,000	$	3.62	$	3.28	$	4.30
Second Quarter	1,820,000	3.28		3.28		3.29
Third Quarter	1,840,000	3.28		3.28		3.29
Fourth Quarter	1,840,000	3.28		3.28		3.29

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

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

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis

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
	Level 1		Level 2		Level 3
	(in thousands)
As of March 31, 2022
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	142,321	$	—	$	—	$	142,321
As of December 31, 2021
Financial Assets
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	53,545	$	—	$	—	$	53,545

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INCENTIVE COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Summary of Incentive Compensation Expense

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,
	2022		2021
	(in thousands)
Cash—short and long-term incentive plans	$	996	$	1,385
Equity-based compensation—restricted common units	927		949
Equity-based compensation—restricted performance units	3,093		2,161
Board of Directors incentive plan	531		352
Total incentive compensation expense	$	5,547	$	4,847

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EARNINGS PER UNIT (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Common and Subordinated Unit

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

	Three Months Ended March 31,
	2022		2021
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	(7,002)	$	16,186
Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	(12,252)	$	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—
Common units	(12,252)		10,936
	$	(12,252)	$	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	(0.06)	$	0.05
Per common unit (diluted)	$	(0.06)	$	0.05
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

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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,
	2022	2021
	(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis	14,969	14,969

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COMMON UNITS (Tables)

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Distributions Made to Limited Partner, by Distribution

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

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BUSINESS AND BASIS OF PRESENTATION - Narrative (Details)	Mar. 31, 2022 state
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20.00%
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located	41

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 99,463	$ 97,142
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	94,691	93,005
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 4,772	$ 4,137

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OIL AND NATURAL GAS PROPERTIES - Acquisitions (Details) - Mineral And Royalty Acreage In Northern Midland Basin $ in Millions	1 Months Ended
	May 31, 2021 USD ($)
Business Acquisition [Line Items]
Total consideration	$ 20.8
Purchase price, cash	10.0
Common unit consideration for acquisition	10.8
Proved oil and natural gas properties	4.9
Unproved oil and natural gas properties	15.6
Net working capital	$ 0.3

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OIL AND NATURAL GAS PROPERTIES - Divestitures (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations - TWL Investments $ in Millions	Sep. 01, 2021 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestures	$ 0.2
Book value of divestures	3.0
Book value of asset retirement obligation	$ 5.7

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OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details) - well	1 Months Ended			3 Months Ended
	May 31, 2021	Mar. 31, 2021	Nov. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Mar. 31, 2022
Asset Acquisition [Line Items]
Partnership agreement term (in years)	10 years
Farmout Agreement | XTO Energy Inc. | San Augustine County, Texas
Asset Acquisition [Line Items]
Partition agreement, ownership interest in partitioned drilling units, percent		100.00%
Farmout Agreement | Aethon Energy | San Augustine County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled				5
Exploratory wells, expected to be drilled per year				12
Farmout Agreement | Pivotal | Angelina County, Texas
Asset Acquisition [Line Items]
Exploratory wells, expected to be drilled					4
Exploratory wells, expected to be drilled per year					15
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent			100.00%
Oil, productive well, number of wells, net						10
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Minimum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent			12.50%
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent			25.00%
Farmout Agreement | Azul-SA, LLC And Canaan Resource Partners | San Augustine County, Texas
Asset Acquisition [Line Items]
Oil, productive well, number of wells, net						4

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OIL AND NATURAL GAS PROPERTIES - Ownership Interest (Details)	1 Months Ended
	May 31, 2021
Partitioned Acreage From XTO
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Asset acquisition, ownership interest, gross, percent	50.00%
Other
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Asset acquisition, ownership interest, gross, percent	25.00%
Canaan Resource Partners | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	64.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	64.00%
Canaan Resource Partners | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	32.00%
Canaan Resource Partners | San Augustine County, Texas | Other | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	40.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	40.00%
Asset acquisition, ownership interest, gross, percent	10.00%
Azul-SA, LLC | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	20.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	20.00%
Azul-SA, LLC | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	10.00%
Azul-SA, LLC | San Augustine County, Texas | Other | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	50.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	50.00%
Azul-SA, LLC | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	12.50%
JWM Oil & Gas LLC | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	16.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	16.00%
JWM Oil & Gas LLC | San Augustine County, Texas | Partitioned Acreage From XTO | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	8.00%
JWM Oil & Gas LLC | San Augustine County, Texas | Other | Farmout Agreement
Extractive Industries [Abstract]
Asset acquisition, ownership interest, in wells operated by others, percent	10.00%
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	10.00%
JWM Oil & Gas LLC | San Augustine County, Texas | Other | Farmout Agreement | Maximum
Asset Acquisition [Line Items]
Asset acquisition, ownership interest, gross, percent	2.50%

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OIL AND NATURAL GAS PROPERTIES - Impairment of Oil and Gas Properties (Details) - USD ($)	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Extractive Industries [Abstract]
Impairment of oil and natural gas properties	$ 0	$ 0

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details)	Mar. 31, 2022 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	6

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 0	$ 0
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	0	0
Gross fair value, liabilities	142,321	53,545
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	142,321	53,545
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	0	0
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	0	0
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	0	0
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	0	0
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	138,028	51,544
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	138,028	51,544
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	4,293	2,001
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	$ 4,293	$ 2,001

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (120,020)	$ (27,882)
Net cash paid (received) on settlements of derivative instruments	31,244	4,523
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	(53,545)	(20,017)
Net change in fair value of commodity derivative instruments	(88,776)	(23,359)
Ending fair value of commodity derivative instruments	(142,321)	(43,376)
Not Designated as Hedging Instrument | Oil
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(48,842)	(24,854)
Net cash paid (received) on settlements of derivative instruments	15,892	4,502
Not Designated as Hedging Instrument | Natural gas and natural gas liquids sales
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(71,178)	(3,028)
Net cash paid (received) on settlements of derivative instruments	$ 15,352	$ 21

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COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument - Swap - Swaps Contract bbl in Thousands, MMBTU in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2023 MMBTU $ / MMBTU
Oil | First Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	220
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl	66.47
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl	55.29
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl	83.91
Oil | Second Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl	66.47
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl	55.29
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl	83.91
Oil | Third Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl	66.47
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl	55.29
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl	83.91
Oil | Fourth Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl	66.47
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl	55.29
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl	83.91
Oil | First Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	180
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / bbl	80.40
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / bbl	78.00
Derivative contract, price range high (in USD per Bbl or MMBtu) | $ / bbl	82.80
Natural gas and natural gas liquids sales | Second Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	8,910
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.12
Derivative contract, price range low (in USD per Bbl or MMBtu)	2.80
Derivative contract, price range high (in USD per Bbl or MMBtu)	4.30
Natural gas and natural gas liquids sales | Third Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	9,000
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.12
Derivative contract, price range low (in USD per Bbl or MMBtu)	2.80
Derivative contract, price range high (in USD per Bbl or MMBtu)	4.30
Natural gas and natural gas liquids sales | Fourth Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	9,000
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.12
Derivative contract, price range low (in USD per Bbl or MMBtu)	2.80
Derivative contract, price range high (in USD per Bbl or MMBtu)	4.30
Natural gas and natural gas liquids sales | First Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	2,700
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.62
Derivative contract, price range low (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range high (in USD per Bbl or MMBtu)	4.30
Natural gas and natural gas liquids sales | First Quarter 2023 | Forecast
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		1,800
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		5.04
Derivative contract, price range low (in USD per Bbl or MMBtu)		5.03
Derivative contract, price range high (in USD per Bbl or MMBtu)		5.05
Natural gas and natural gas liquids sales | Second Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	1,820
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range low (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range high (in USD per Bbl or MMBtu)	3.29
Natural gas and natural gas liquids sales | Second Quarter 2023 | Forecast
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		1,820
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		5.04
Derivative contract, price range low (in USD per Bbl or MMBtu)		5.03
Derivative contract, price range high (in USD per Bbl or MMBtu)		5.05
Natural gas and natural gas liquids sales | Third Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	1,840
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range low (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range high (in USD per Bbl or MMBtu)	3.29
Natural gas and natural gas liquids sales | Third Quarter 2023 | Forecast
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		1,840
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		5.04
Derivative contract, price range low (in USD per Bbl or MMBtu)		5.03
Derivative contract, price range high (in USD per Bbl or MMBtu)		5.05
Natural gas and natural gas liquids sales | Fourth Quarter 2023
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	1,840
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range low (in USD per Bbl or MMBtu)	3.28
Derivative contract, price range high (in USD per Bbl or MMBtu)	3.29
Natural gas and natural gas liquids sales | Fourth Quarter 2023 | Forecast
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU		1,840
Derivative contract, weighted average price (in USD per Bbl or MMBtu)		5.04
Derivative contract, price range low (in USD per Bbl or MMBtu)		5.03
Derivative contract, price range high (in USD per Bbl or MMBtu)		5.05

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FAIR VALUE MEASUREMENTS - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 0	$ 0
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	0	0
Gross fair value, liabilities	142,321	53,545
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	142,321	53,545
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	0	0
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	142,321	53,545
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	0	0
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	142,321	53,545
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	$ 0	$ 0

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CREDIT FACILITY (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021	Apr. 30, 2022	Oct. 31, 2021
Line Of Credit Facility [Line Items]
Current ratio	1.0
Credit facility	$ 69,000	$ 89,000
Senior Line of Credit | Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity	$ 1,000,000
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (percent)	10.00%
Borrowing base				$ 400,000
Weighted average interest rate (percent)	2.94%	2.61%
Interest payable, term	90 days
Borrowing base threshold (percent)	50.00%
Percentage of availability of lenders' commitments, distributions not permitted	10.00%
Ratio of total debt to EBITDAX, distributions not permitted	3.0
Credit facility	$ 69,000	$ 89,000
Unused portion of current borrowing base	$ 331,000	$ 311,000
Senior Line of Credit | Revolving Credit Facility | Subsequent Event
Line Of Credit Facility [Line Items]
Borrowing base			$ 400,000
Senior Line of Credit | Revolving Credit Facility | Federal Funds
Line Of Credit Facility [Line Items]
Interest rate (percent)	0.50%
Senior Line of Credit | Revolving Credit Facility | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.00%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.375%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)	0.50%
Senior Line of Credit | Revolving Credit Facility | Minimum
Line Of Credit Facility [Line Items]
Interest payable, term	90 days
Current ratio	1.0
Senior Line of Credit | Revolving Credit Facility | Minimum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.50%	1.50%
Senior Line of Credit | Revolving Credit Facility | Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3.5
Senior Line of Credit | Revolving Credit Facility | Maximum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.50%	3.50%
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%	2.50%

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INCENTIVE COMPENSATION - Summary of Incentive Compensation Expense (Details) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2022 USD ($) MMBoe $ / shares shares	Mar. 31, 2021 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Mboe per day | MMBoe	42,000
Current ratio	1.0
Performance Cash Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 4,700
Performance Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 16,900
Grant of stock units (in shares) | shares	1,463,202
Weighted-average grant date fair value (in units per share) | $ / shares	$ 11.55
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash—short and long-term incentive plans	$ 996	$ 1,385
Incentive compensation expense	5,547	4,847
General and administrative expenses | Restricted Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	927	949
General and administrative expenses | Restricted Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	3,093	2,161
General and administrative expenses | Common units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive compensation expense	$ 531	$ 352

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PREFERRED UNITS (Details) - Series B Cumulative Convertible Preferred Units $ / shares in Units, $ in Thousands		3 Months Ended
	Nov. 28, 2017 USD ($) $ / shares shares	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Class of Stock [Line Items]
Shares, price per share (in dollars per share) | $ / shares	$ 20.3926
Proceeds from issuance of convertible preferred stock	$ 300,000
Preferred units distribution rate	7.00%	7.00%
Preferred unit conversion ratio	1
Minimum underlying value for conversion trigger	$ 10,000
Preferred units, outstanding value		$ 298,361	$ 298,361
Accrued distributions		$ 5,300	$ 5,300
Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares) | shares	14,711,219

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EARNINGS PER UNIT - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Earnings Per Share [Abstract]
NET INCOME (LOSS)	$ (7,002)	$ 16,186
Distributions on Series B cumulative convertible preferred units	(5,250)	(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	(12,252)	10,936
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	(12,252)	10,936
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ (12,252)	$ 10,936
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ (0.06)	$ 0.05
Per common unit (diluted) (in dollars per share)	$ (0.06)	$ 0.05
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic) (in shares)	209,323	207,442
Effect of dilutive securities (in shares)	0	0
Weighted average units outstanding (diluted) (in shares)	209,323	207,442

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EARNINGS PER UNIT - Potentially Dilutive Securities Excluded from the Computation of Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Series B cumulative convertible preferred units on an as-converted basis | Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU (in shares)	14,969	14,969

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COMMON UNITS - Narrative (Details) - USD ($) $ in Millions		3 Months Ended
	Nov. 28, 2017	Mar. 31, 2022	Nov. 05, 2018
November 2018 Repurchase Program
Class of Stock [Line Items]
Stock repurchase program, authorized amount			$ 75.0
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)		15.00%
Preferred units distribution rate	7.00%	7.00%
Common units | November 2018 Repurchase Program
Class of Stock [Line Items]
Treasury stock, acquired (in shares)		0
Treasury stock, value, acquired, cost method		$ 4.2

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COMMON UNITS - Per share distributions to common and subordinated unitholders (Details) - Common units - $ / shares	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Class of Stock [Line Items]
Distributions paid per common unit (in dollars per share)	$ 0.2700	$ 0.1750
Distributions declared per common unit (in dollars per share)	$ 0.2700	$ 0.1750

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SUBSEQUENT EVENTS (Details) - Common units - $ / shares		3 Months Ended
	Apr. 25, 2022	Mar. 31, 2022	Mar. 31, 2021
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)		$ 0.2700	$ 0.1750
Subsequent Event
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share)	$ 0.40