Black Stone Minerals, L.P. - Quarter Report: 2022 June (Form 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 June 30, 2022


☐			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 July 29, 2022, there were 209,401,737 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	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 5.	Other Information	35
Item 6.	Exhibits	36

	Signatures	37

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)


	June 30, 2022		December 31, 2021
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12,158	$	8,876
Accounts receivable	140,569		97,142
Commodity derivative assets	316		—

Prepaid expenses and other current assets	2,457		1,956
TOTAL CURRENT ASSETS	155,500		107,974
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $925,707 and $937,395 at June 30, 2022 and December 31, 2021, respectively	3,000,991		3,001,627
Accumulated depreciation, depletion, amortization, and impairment	(1,892,235)		(1,869,731)
Oil and natural gas properties, net	1,108,756		1,131,896
Other property and equipment, net of accumulated depreciation of $13,150 and $12,931 at June 30, 2022 and December 31, 2021, respectively	1,122		1,440
NET PROPERTY AND EQUIPMENT	1,109,878		1,133,336
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,315		6,611
TOTAL ASSETS	$	1,272,693	$	1,247,921
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,586	$	5,944
Accrued liabilities	13,103		17,589
Commodity derivative liabilities	106,080		51,544
Other current liabilities	2,048		2,063
TOTAL CURRENT LIABILITIES	124,817		77,140
LONG–TERM LIABILITIES
Credit facility	86,000		89,000
Accrued incentive compensation	1,063		838
Commodity derivative liabilities	3,422		2,001
Asset retirement obligations	12,599		12,561
Other long-term liabilities	2,104		2,752
TOTAL LIABILITIES	230,005		184,292
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at June 30, 2022 and December 31, 2021, respectively	298,361		298,361
EQUITY
Partners' equity – general partner interest	—		—
Partners' equity – common units, 209,399 and 208,666 units outstanding at June 30, 2022 and December 31, 2021, respectively	744,327		765,268
TOTAL EQUITY	744,327		765,268
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,272,693	$	1,247,921

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
REVENUE
Oil and condensate sales	$	94,296	$	53,936	$	170,127	$	98,112
Natural gas and natural gas liquids sales	111,181		56,481		186,935		99,370
Lease bonus and other income	2,244		7,505		7,103		9,890
Revenue from contracts with customers	207,721		117,922		364,165		207,372
Gain (loss) on commodity derivative instruments	(27,349)		(59,480)		(147,369)		(87,362)
TOTAL REVENUE	180,372		58,442		216,796		120,010
OPERATING (INCOME) EXPENSE
Lease operating expense	3,199		3,837		6,360		6,501
Production costs and ad valorem taxes	19,504		9,296		33,453		21,138
Exploration expense	2		2		182		1,075
Depreciation, depletion, and amortization	11,893		15,796		22,810		31,428

General and administrative	12,519		12,187		26,282		25,039
Accretion of asset retirement obligations	205		298		407		590
(Gain) loss on sale of assets, net	(17)		—		(17)		—
TOTAL OPERATING EXPENSE	47,305		41,416		89,477		85,771
INCOME (LOSS) FROM OPERATIONS	133,067		17,026		127,319		34,239
OTHER INCOME (EXPENSE)
Interest and investment income	2		—		2		—
Interest expense	(1,362)		(1,628)		(2,571)		(2,838)
Other income (expense)	81		31		36		214
TOTAL OTHER EXPENSE	(1,279)		(1,597)		(2,533)		(2,624)
NET INCOME (LOSS)	131,788		15,429		124,786		31,615

Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)		(10,500)		(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	126,538	$	10,179	$	114,286	$	21,115
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—	$	—
Common units	126,538		10,179		114,286		21,115
	$	126,538	$	10,179	$	114,286	$	21,115
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.60	$	0.05	$	0.55	$	0.10
Per common unit (diluted)	$	0.59	$	0.05	$	0.55	$	0.10
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	209,397		207,945		209,360		207,695
Weighted average common units outstanding (diluted)	224,366		207,945		209,360		207,695

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)


	Common units	Partners' equity — common units		Total equity
BALANCE AT DECEMBER 31, 2021	208,666	$	765,268	$	765,268
Repurchases of common units	(262)	(2,991)		(2,991)


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



Restricted units granted, net of forfeitures	7	—		—
Equity–based compensation	—	2,273		2,273
Distributions	—	(83,759)		(83,759)
Charges to partners' equity for accrued distribution equivalent rights	—	(513)		(513)
Distributions on Series B cumulative convertible preferred units	—	(5,250)		(5,250)
Net income (loss)	—	131,788		131,788
BALANCE AT JUNE 30, 2022	209,399	$	744,327	$	744,327

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)


	Common units	Partners' equity — common units		Total equity
BALANCE AT DECEMBER 31, 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


Issuance of common units for property acquisitions	1,088	10,766		10,766
Restricted units granted, net of forfeitures	7	—		—
Equity–based compensation	—	2,820		2,820
Distributions	—	(36,321)		(36,321)
Charges to partners' equity for accrued distribution equivalent rights	—	(180)		(180)
Distributions on Series B cumulative convertible preferred units	—	(5,250)		(5,250)
Net income (loss)	—	15,429		15,429
BALANCE AT JUNE 30, 2021	208,637	$	725,693	$	725,693

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended June 30,
	2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	124,786	$	31,615
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	22,810		31,428

Accretion of asset retirement obligations	407		590
Amortization of deferred charges	694		884
(Gain) loss on commodity derivative instruments	147,369		87,362
Net cash (paid) received on settlement of commodity derivative instruments	(93,696)		(21,868)
Equity-based compensation	7,275		6,533
Exploratory dry hole expense	—		1,049
(Gain) loss on sale of assets, net	(17)		—
Changes in operating assets and liabilities:
Accounts receivable	(43,192)		(6,159)
Prepaid expenses and other current assets	(501)		(448)
Accounts payable, accrued liabilities, and other	(5,359)		(5,247)
Settlement of asset retirement obligations	(437)		(160)
NET CASH PROVIDED BY OPERATING ACTIVITIES	160,139		125,579
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	—		(10,064)
Additions to oil and natural gas properties	(10,072)		(2,606)
Additions to oil and natural gas properties leasehold costs	—		(21)
Purchases of other property and equipment	(41)		(63)
Proceeds from the sale of oil and natural gas properties	17		—
Proceeds from farmouts of oil and natural gas properties	9,951		—
NET CASH USED IN INVESTING ACTIVITIES	(145)		(12,754)
CASH FLOWS FROM FINANCING ACTIVITIES

Distributions to common unitholders	(140,221)		(72,593)
Distributions to Series B cumulative convertible preferred unitholders	(10,500)		(10,500)


Repurchases of common units	(2,991)		(1,957)
Borrowings under credit facility	153,000		84,000
Repayments under credit facility	(156,000)		(109,000)
Debt issuance costs and other	—		(3,528)
NET CASH USED IN FINANCING ACTIVITIES	(156,712)		(113,578)
NET CHANGE IN CASH AND CASH EQUIVALENTS	3,282		(753)
CASH AND CASH EQUIVALENTS – beginning of the period	8,876		1,796
CASH AND CASH EQUIVALENTS – end of the period	$	12,158	$	1,043
SUPPLEMENTAL DISCLOSURE
Interest paid	$	1,864	$	1,944

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."

Basis of Presentation

The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021 ("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 six months ended June 30, 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.

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 six months ended June 30, 2022.

Accounts Receivable

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


	June 30, 2022		December 31, 2021

	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	134,278	$	93,005
Other	6,291		4,137
Total accounts receivable	$	140,569	$	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. The Partnership had no acquisition activity during the six months ended June 30, 2022.

Divestitures

In the third quarter of 2021, the Partnership closed on the divestiture of its wholly owned subsidiary, TLW Investments, L.L.C. ("TLW"), effective September 1, 2021 for total proceeds of $0.2 million. TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas. TLW's assets and liabilities consisted of oil and natural gas properties with a net book value of $3.0 million and asset retirement obligations with a book value of $5.7 million at the time of sale. The Partnership had no material divestiture activity during the six months ended June 30, 2022.

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.

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 June 30, 2022, six wells have been spud by Aethon in the contract area subject to the Canaan, Azul, and JWM Farmouts.

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

Brent Miller Area


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

Other Areas


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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Angelina Farmout

In May 2020, the Partnership entered into a development agreement with Aethon to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of 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 June 30, 2022, fourteen 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 and six months ended June 30, 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 June 30, 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 June 30, 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 June 30, 2022, the Partnership had seven counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date:


		June 30, 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	$	702	$	(386)	$	316
Long-term asset	Deferred charges and other long-term assets	2,886		(918)		1,968
Total assets		$	3,588	$	(1,304)	$	2,284
Liabilities:
Current liability	Commodity derivative liabilities	$	106,466	$	(386)	$	106,080
Long-term liability	Commodity derivative liabilities	4,340		(918)		3,422
Total liabilities		$	110,806	$	(1,304)	$	109,502


		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

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 June 30,				Six Months Ended June 30,
Derivatives not designated as hedging instruments	2022		2021		2022		2021
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(142,321)	$	(43,376)	$	(53,545)	$	(20,017)
Gain (loss) on oil derivative instruments	(16,275)		(34,215)		(65,117)		(59,069)
Gain (loss) on natural gas derivative instruments	(11,074)		(25,265)		(82,252)		(28,293)
Net cash paid (received) on settlements of oil derivative instruments	26,345		15,910		42,237		20,412
Net cash paid (received) on settlements of natural gas derivative instruments	36,107		1,435		51,459		1,456
Net change in fair value of commodity derivative instruments	35,103		(42,135)		(53,673)		(65,494)
Ending fair value of commodity derivative instruments	$	(107,218)	$	(85,511)	$	(107,218)	$	(85,511)

The Partnership had the following open derivative contracts for oil as of June 30, 2022:


		Weighted Average Price (Per Bbl)		Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)			Low		High
Oil Swap Contracts:
2022

Second Quarter	220,000	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
Second Quarter	90,000	$	89.50	$	89.50	89.50
Third Quarter	90,000	$	89.50	$	89.50	89.50
Fourth Quarter	90,000	$	89.50	$	89.50	89.50

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 June 30, 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	—	$	—	$	—	$	—
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	4,500,000	$	4.19	$	3.28	$	5.05
Second Quarter	3,640,000	4.16		3.28		5.05
Third Quarter	3,680,000	4.16		3.28		5.05
Fourth Quarter	3,680,000	4.16		3.28		5.05

The Partnership entered into the following derivative contracts for natural gas subsequent to June 30, 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	2,700,000	$	5.61	$	5.10	$	6.00
Second Quarter	2,730,000	5.61		5.10		6.00
Third Quarter	2,760,000	5.61		5.10		6.00
Fourth Quarter	2,760,000	5.61		5.10		6.00

NOTE 5 - FAIR VALUE MEASUREMENTS

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of June 30, 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 June 30, 2022
Financial Assets
Commodity derivative instruments	$	—	$	3,588	$	—	$	(1,304)	$	2,284
Financial Liabilities
Commodity derivative instruments	$	—	$	110,806	$	—	$	(1,304)	$	109,502
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 June 30, 2022 or December 31, 2021.

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 June 30, 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 4.12% and 2.61% as of June 30, 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 June 30, 2022, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $86.0 million and $89.0 million at June 30, 2022 and December 31, 2021, respectively. The unused portion of the available borrowings under the Credit Facility were $314.0 million and $311.0 million at June 30, 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.

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 June 30, 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

	(in thousands)
Cash—short and long-term incentive plans	$	1,963	$	1,729	$	2,959	$	3,114
Equity-based compensation—restricted common units	1,049		1,037		1,976		1,986
Equity-based compensation—restricted performance units	1,144		1,697		4,237		3,858
Board of Directors incentive plan	531		337		1,062		689
Total incentive compensation expense	$	4,687	$	4,800	$	10,234	$	9,647

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 $5.0 million for the performance cash awards and $17.1 million for the performance equity awards (1,476,943 performance units with a weighted-average grant date fair value of $11.58 per unit). As of June 30, 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 June 30, 2022 and December 31, 2021. The Series B cumulative convertible preferred units are classified

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	131,788	$	15,429	$	124,786	$	31,615

Distributions on Series B cumulative convertible preferred units	(5,250)		(5,250)		(10,500)		(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$	126,538	$	10,179	$	114,286	$	21,115
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—	$	—
Common units	126,538		10,179		114,286		21,115
	$	126,538	$	10,179	$	114,286	$	21,115
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)	$	0.60	$	0.05	$	0.55	$	0.10
Per common unit (diluted)1	$	0.59	$	0.05	$	0.55	$	0.10
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)	209,397		207,945		209,360		207,695
Effect of dilutive securities	14,969		—		—		—
Weighted average common units outstanding (diluted)	224,366		207,945		209,360		207,695

1 For the Three Months Ended June 30, 2022, diluted net income (loss) attributable to common units included distributions on Series B cumulative convertible preferred units of $5.3 million.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:


	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021

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

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Distributions declared and paid per common unit	$	0.4000	$	0.1750	$	0.6700	$	0.3500

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 six months ended June 30, 2022. As of June 30, 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 July 25, 2022, the Board approved a distribution for the three months ended June 30, 2022 of $0.42 per common unit. Distributions will be payable on August 19, 2022 to unitholders of record at the close of business on August 12, 2022.

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;

•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 June 30, 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.

Recent Developments

Shelby Trough Development Update

Aethon has successfully turned eight wells to sales and has commenced operations on six additional wells under the development agreement covering Angelina County. Aethon is currently drilling two wells and completing four wells under the separate development agreement covering San Augustine County. Aethon’s completions are more intensive than those of prior operators in the area and result in higher initial flowback rates. Additionally, XTO Energy has finished drilling operations and started completing the 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 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. In addition to the test well program, twelve new horizontal wells have been drilled on our acreage to test various portions of the field across a four-county area. Although production results have varied on those wells, the play is becoming better delineated, with consistent well performance across certain areas. Seven operators are actively engaged in redevelopment of the field, with four rigs currently running in the play. To date, twelve wells with modern completions are now producing in the area, and an additional six are currently either being drilled or completed.

Business Environment

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

COVID-19 Pandemic and Market Conditions

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

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 half 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.

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


	2022				2021
Benchmark Prices1	Second Quarter		First Quarter			Second Quarter		First Quarter
WTI spot oil price ($/Bbl)	$	107.76	$	100.53		$	73.52	$	59.19
Henry Hub spot natural gas ($/MMBtu)	6.54		5.46			3.79		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 have been volatile in 2022 resulting from the uncertainty in the global natural gas markets leading up to and following Russia's full-scale invasion of Ukraine, as well as from weather-related fluctuations in natural gas demand. Net natural gas exports averaged 11.2 Bcf per day in the first half of 2022, a 15% increase from the 2021 average. On June 9, 2022, Freeport LNG shut down its Gulf Coast LNG export facility, which represents approximately 20% of the total U.S. export capacity, due to an explosion at the facility. The EIA expects U.S. LNG exports to decline due to the outage at the Freeport LNG export facility, forecasting average exports of 10.5 Bcf per day for the rest of 2022 and 12.7 Bcf per day for 2023. In a June 30, 2022 statement, Freeport LNG indicated that it "continues to target year-end for a return to full production." 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	Second Quarter	First Quarter	Second Quarter	First Quarter
Oil	594	531	372	324
Natural gas	157	137	98	92
Other	2	2	—	1
Total	753	670	470	417

1 Source: Baker Hughes Incorporated

Natural Gas Storage

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

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA estimates that natural gas inventories will conclude the injection season in October 2022 at 3.5 Tcf, which is 6% 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	Second Quarter	First Quarter	Second Quarter	First Quarter
East	461	268	513	307
Midwest	535	317	623	401
Mountain	134	89	173	112
Pacific	235	161	244	194
South Central	886	581	1,005	749
Total	2,251	1,416	2,558	1,763

1 Source: EIA

How We Evaluate Our Operations

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

•volumes of oil and natural gas produced;

•commodity prices including the effect of derivative instruments; and

•Adjusted EBITDA and Distributable cash flow.

Volumes of Oil and Natural Gas Produced

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

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

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

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

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

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

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

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

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

Hedging

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

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

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of June 30, 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 June 30, 2022, we have hedged 88% and 15% of our available oil and condensate hedge volumes for 2022 and 2023, respectively. As of June 30, 2022, we have also hedged 76% and 30% 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.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021

	(in thousands)
Net income (loss)	$	131,788	$	15,429	$	124,786	$	31,615
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization	11,893		15,796		22,810		31,428

Interest expense	1,362		1,628		2,571		2,838
Income tax expense (benefit)	(14)		6		89		(151)
Accretion of asset retirement obligations	205		298		407		590
Equity–based compensation	2,724		3,071		7,275		6,533
Unrealized (gain) loss on commodity derivative instruments	(35,103)		42,135		53,673		65,494
(Gain) loss on sale of assets, net	(17)		—		(17)		—
Adjusted EBITDA	112,838		78,363		211,594		138,347
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue	(6)		(5)		(15)		(14)
Cash interest expense	(1,015)		(1,001)		(1,877)		(1,954)
Preferred unit distributions	(5,250)		(5,250)		(10,500)		(10,500)
Distributable cash flow	$	106,567	$	72,107	$	199,202	$	125,879

Results of Operations

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021

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


	Three Months Ended June 30,
	2022		2021		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	899		860		39		4.5	%
Natural gas (MMcf)1	12,895		15,676		(2,781)		(17.7)	%
Equivalents (MBoe)	3,048		3,473		(425)		(12.2)	%
Equivalents/day (MBoe)	33.5		38.2		(4.7)		(12.3)	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	104.89	$	62.72	$	42.17	67.2	%
Natural gas ($/Mcf)1	8.62		3.60		5.02		139.4	%
Equivalents ($/Boe)	$	67.41	$	31.79	$	35.62	112.0	%
Revenue:
Oil and condensate sales	$	94,296	$	53,936	$	40,360	74.8	%
Natural gas and natural gas liquids sales1	111,181		56,481		54,700		96.8	%
Lease bonus and other income	2,244		7,505		(5,261)		(70.1)	%
Revenue from contracts with customers	207,721		117,922		89,799		76.2	%
Gain (loss) on commodity derivative instruments	(27,349)		(59,480)		32,131		(54.0)	%
Total revenue	$	180,372	$	58,442	$	121,930	208.6	%
Operating expenses:
Lease operating expense	$	3,199	$	3,837	$	(638)	(16.6)	%
Production costs and ad valorem taxes	19,504		9,296		10,208		109.8	%
Exploration expense	2		2		—		—	%
Depreciation, depletion, and amortization	11,893		15,796		(3,903)		(24.7)	%

General and administrative	12,519		12,187		332		2.7	%
Other expense:
Interest expense	1,362		1,628		(266)		(16.3)	%

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 June 30, 2022 increased compared to the quarter ended June 30, 2021. The increase in total revenue from the corresponding period is primarily due to an increase in sales of oil and condensate, natural gas, and NGLs in addition to unrealized gains from our commodity derivative instruments partially offset by a decrease in our lease bonus and other income.

Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for quarters ended June 30, 2022 and 2021.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended June 30, 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, in addition to lower working interest volumes in the area as a result of the farmout agreements put in place in 2017. Mineral and royalty interest production accounted for 90% and 83% of our natural gas volumes for the quarters ended June 30, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments. During the second quarter of 2022, we recognized a decrease 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 June 30, 2022, we recognized $62.5 million of realized losses and $35.1 million of unrealized gains from our oil and natural gas commodity contracts, compared to $17.4 million of realized losses and $42.1 million of unrealized losses in the same period in 2021. The unrealized gains on our commodity contracts during the second quarter of 2022 and the unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

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 second quarter of 2022 was lower than the same period in 2021. Leasing activity in the Austin Chalk play made up the majority of lease bonus and other income for the second quarter of 2022, and a substantial portion for the second quarter of 2021.

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 decreased for the quarter ended June 30, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes as a result of the TLW divestiture in the third quarter of 2021 and continued declines from our remaining working interest properties. Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

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 June 30, 2022, production costs and ad valorem taxes increased as compared to the quarter ended June 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense was minimal for the quarter ended June 30, 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 June 30, 2022 as compared to the same period in 2021, primarily due to lower natural gas production.

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 June 30, 2022, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to an increase in cash compensation.

Interest expense. Interest expense was lower in the second quarter of 2022 relative to the corresponding period in 2021, due to lower average outstanding borrowings under our Credit Facility partially offset by higher interest rates.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

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



	Six Months Ended June 30,
	2022		2021		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	1,730		1,689		41		2.4	%
Natural gas (MMcf)1	25,654		30,586		(4,932)		(16.1)	%
Equivalents (MBoe)	6,006		6,787		(781)		(11.5)	%
Equivalents/day (MBoe)	33.2		37.5		(4.3)		(11.5)	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	98.34	$	58.09	$	40.25	69.3	%
Natural gas ($/Mcf)1	7.29		3.25		4.04		124.3	%
Equivalents ($/Boe)	$	59.45	$	29.10	$	30.35	104.3	%
Revenue:
Oil and condensate sales	$	170,127	$	98,112	$	72,015	73.4	%
Natural gas and natural gas liquids sales1	186,935		99,370		87,565		88.1	%
Lease bonus and other income	7,103		9,890		(2,787)		(28.2)	%
Revenue from contracts with customers	364,165		207,372		156,793		75.6	%
Gain (loss) on commodity derivative instruments	(147,369)		(87,362)		(60,007)		68.7	%
Total revenue	$	216,796	$	120,010	$	96,786	80.6	%
Operating expenses:
Lease operating expense	$	6,360	$	6,501	$	(141)	(2.2)	%
Production costs and ad valorem taxes	33,453		21,138		12,315		58.3	%
Exploration expense	182		1,075		(893)		(83.1)	%
Depreciation, depletion, and amortization	22,810		31,428		(8,618)		(27.4)	%

General and administrative	26,282		25,039		1,243		5.0	%
Other expense:
Interest expense	2,571		2,838		(267)		(9.4)	%

Revenue

Total revenue for the six months ended June 30, 2022 increased compared to the corresponding prior period. The increase in total revenue is due to increased sales of oil and condensate, natural gas, and NGLs for the six months ended June 30, 2022 compared to the same period in 2021. The overall increase in total revenue was partially offset by an increased loss from our commodity derivative instruments and a decrease in lease bonus and other income for the six months ended June 30, 2022 compared to the same period in 2021.

Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for both the six months ended June 30, 2022 and 2021.

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes. 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, in addition to lower working interest volumes in the area as a result of the farmout agreements put in place in 2017. Mineral and royalty interest production accounted for 89% and 84% of our natural gas volumes for the six months ended June 30, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2022, we recognized an increased loss from our commodity derivative instruments compared to the same period in 2021. In the six months ended June 30, 2022, we recognized $93.7 million of realized losses and $53.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $21.9 million of realized gains and $65.5 million of unrealized losses in the same period in 2021. The unrealized losses on our commodity contracts during the six months ended June 30, 2022 and 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2022 was lower than the same period in 2021. Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the six months ended June 30, 2022, and for the corresponding prior period.

Operating and Other Expenses

Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes as a result of the TLW divestiture in the third quarter of 2021 and continued declines from our remaining working interest properties. Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

Production costs and ad valorem taxes. For the six months ended June 30, 2022, production costs and ad valorem taxes increased as compared to the six months ended June 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

Exploration expense. Exploration expense for the six months ended June 30, 2022 was minimal. Exploration expense for the six months ended June 30, 2021 primarily related to a dry hole drilled in the first quarter of 2021.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization decreased for the six months ended June 30, 2022 as compared to the same period in 2021, primarily due to lower natural gas production volumes.

General and administrative. For the six months ended June 30, 2022, general and administrative expenses increased as compared to the same period in 2021, primarily due to an increase in cash compensation and a $0.7 million increase in equity incentive compensation. The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from larger upward movements in our common unit price during the six months ended June 30, 2022 compared to the corresponding prior period.

Interest expense. Interest expense was lower in the six months ended June 30, 2022 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility partially offset by higher interest rates.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties. As of June 30, 2022, we had outstanding borrowings of $86.0 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:


	Six Months Ended June 30,
	2022		2021		Change

	(in thousands)
Cash flows provided by operating activities	$	160,139	$	125,579	$	34,560
Cash flows provided by (used in) investing activities	(145)		(12,754)		12,609
Cash flows used in financing activities	(156,712)		(113,578)		(43,134)

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 six months ended June 30, 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 six months ended June 30, 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 six months ended June 30, 2022 decreased as compared to the same period of 2021. The decrease was primarily due to minimal cash paid for acquisitions of oil and natural gas properties in the six months ended June 30, 2022 compared to the same period of 2021.

Financing Activities. Cash flows used in financing activities increased for the six months ended June 30, 2022 as compared to the same period of 2021. The increase was primarily due to higher distributions to unitholders.

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 six months ended June 30, 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.

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 June 30, 2022, we had outstanding borrowings of $86.0 million at a weighted-average interest rate of 4.12%.

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 June 30, 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 June 30, 2022, we were in compliance with all debt covenants.

Contractual Obligations

As of June 30, 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 June 30, 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 June 30, 2022 by 10%. This results in an approximate 1% reduction of proved reserve volumes as compared to the unadjusted June 30, 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 June 30, 2022, we had seven counterparties, all of which were rated Baa1 or better by Moody’s and are lenders under our Credit Facility.

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

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. As of June 30, 2022, we had $86.0 million of outstanding borrowings under our Credit Facility, bearing interest at a weighted-average interest rate of 4.12%. 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 $0.4 million for the six months ended June 30, 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.

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 June 30, 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 June 30, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our 2021 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.

Rising inflation could result in increased interest rates and recession, both of which may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay quarterly distributions on our common units.

Over the past year, inflation has continued to rise, reaching recent historical highs. As the Federal Reserve and other central banks take steps to moderate inflation, including by increasing interest rates, the risks of a recession and associated economic slowdown increase.

The federal funds rate has increased from effectively zero in early 2022 to approximately 2.5% in July 2022. As interest rates increase, the trading price of our common units could decline. Please see "Risk Factors - Distributions to Unitholders: Price of Units and Other Risks - Increases in interest rates may cause the market price of our common units to decline." in our Form 10-K.

In 2022, the U.S. economy showed negative growth for two consecutive quarters, which could signal recession. An economic slowdown, or the risk of an economic slowdown, contributes to volatility in commodity prices and decreases certainty for our operators. Risk of recession, even if not realized, could result in decreased drilling activity by operators and reduced demand for oil and natural gas. Reduced production or a decrease in the prices we realize could both adversely affect our cash generated from operations and our ability to pay quarterly distributions.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits



Exhibit Number						Description

3.1						Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.2						Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.3						First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).

3.4						Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).

3.5						Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

3.6						Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).

3.7						Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of the Black Stone Minerals, L.P., dated as of April 22, 2020 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on April 24, 2020 (SEC File No. 001-37362)).

4.1						Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

31.1*						Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*						Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1*						Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS*						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*						Inline XBRL Schema Document

101.CAL*						Inline XBRL Calculation Linkbase Document

101.LAB*						Inline XBRL Label Linkbase Document

101.PRE*						Inline XBRL Presentation Linkbase Document

101.DEF*						Inline XBRL Definition Linkbase Document

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

* Filed or furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	BLACK STONE MINERALS, L.P.

	By:	Black Stone Minerals GP, L.L.C., its general partner

Date: August 2, 2022	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		Chief Executive Officer and Chairman
		(Principal Executive Officer)

Date: August 2, 2022	By:	/s/ Jeffrey P. Wood
		Jeffrey P. Wood
		President and Chief Financial Officer
		(Principal Financial Officer)