UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

FORM 10-Q

____________________

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

For the quarterly period ended March 31, 2022

or

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

For the transition period from ____________ to ____________

Commission file number: 001-38870

Brigham Minerals, Inc.

(Exact name of registrant as specified in its charter)

Delaware	83-1106283
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer  Identification No.)
5914 W. Courtyard Drive, Suite 200 Austin, Texas	78730
(Address of principal executive offices)	(Zip code)

(512) 220-6350

(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
Class A common stock, par value $0.01	MNRL	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 x No o

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 such files). Yes x No o

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 Exchange Act). Yes ☐ No x

The registrant had 52,321,848 shares of Class A common stock and 8,201,129 shares of Class B common stock outstanding as of April 30, 2022.

BRIGHAM MINERALS, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2022

TABLE OF CONTENTS

		Page
	Glossary of Oil and Natural Gas Terms	ii
	Cautionary Statement Regarding Forward-Looking Statements	iv
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets at March 31, 2022 and December 31, 2021	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2022 and 2021	2
	Condensed Consolidated Statements of Changes in Equity for the Three Months Ended March 31, 2022 and 2021	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2022 and 2021	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	39
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 6.	Exhibits	41
	SIGNATURES	42

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Term	Definition
Basin	A depression in the Earth's crust formed from plate tectonics providing accommodation space for the accumulation of sedimentary rocks and organic material. When subjected to the appropriate depth and duration of burial, hydrocarbon generation can occur creating oil and natural gas bearing strata.
Bbl	One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Boe	One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d	One Boe per day.
British thermal unit or Btu	The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Development well	A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential	An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Drilled but Uncompleted Well (DUC)	A well that an operator has spud but has not yet begun hydraulic fracturing or completion operations.
Gross acres or gross wells	The total acres or wells, as the case may be, in which a mineral or royalty interest is owned.
MBbl	One thousand barrels of crude oil, condensate or NGLs.
MBoe	One thousand Boe.
Mcf	One thousand cubic feet of natural gas.
Mcf/d	One Mcf per day.
MMBtu	One million British thermal units.
MMcf	One million cubic feet of natural gas.
Net royalty acre	Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.
Net well	The percentage of net revenue interest an owner has out of a gross well. For example, an owner who has an 25% royalty interest in a single well owns 0.25 net wells.
NGLs	Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX	The New York Mercantile Exchange.
Operator	The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
Possible Reserves	Reserves that are less certain to be recovered than probable reserves.
Probable reserves	Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.
Prospect	A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves	Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

ii

Term	Definition
Proved reserves	Those quantities of oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
Proved undeveloped reserves or PUDs	Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The following rules apply to PUDs: (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances; (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time; and (iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Realized price	The cash market price less all applicable deductions such as quality, transportation and demand adjustments.
Reserves	Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty	An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Spot market price	The cash market price without reduction for expected quality, transportation and demand adjustments.
Spud	Commenced drilling operations on an identified location.
Undeveloped acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas or NGLs regardless of whether such acreage contains proved reserves.

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 (this "Quarterly Report") includes “forward-looking statements.” All statements, other than statements of historical fact, included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. In particular, our statements regarding the ongoing COVID-19 pandemic and its potential future impact on our business, financial position, results of operations and cash flows are forward-looking statements. When used in this Quarterly Report, the words “may,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions and the negative of such words and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2021 (the "Annual Report"), as well as the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (the "SEC").

The following important factors, in addition to those discussed elsewhere in this Quarterly Report, could affect the future results of the energy industry in general, and our company in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

•our ability to execute on our business objectives;

•the effect of changes in commodity prices;

•the level of production on our properties;

•risks associated with the drilling and operation of oil and natural gas wells;

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

•legislative or regulatory actions pertaining to hydraulic fracturing, including restrictions on the use of water;

•the availability of pipeline capacity and transportation facilities;

•the effect of existing and future laws and regulatory actions;

•the impact of derivative instruments;

•conditions in the capital markets and our ability to obtain capital on favorable terms or at all;

•rising interest rates and its effects on our cost of capital;

•the overall supply and demand for oil, natural gas and NGLs, and regional supply and demand factors, storage availability, delays, or interruptions of production, including voluntary shut-ins;

•operator budget constraints and their ability to obtain capital on favorable terms or at all;

•the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other significant producers and governments and the ability of such producers to agree to and maintain oil price and production controls;

•competition from others in the energy industry;

•the impact of reduced drilling activity in our focus areas and uncertainty as to whether development projects will be pursued;

•the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine;

iv

•global or national health events, including the ongoing COVID-19 pandemic and its resulting economic effects;

•the effects of current or future litigation, including the recent U.S. Supreme Court ruling involving the Muscogee (Creek) Nation reservation in Eastern Oklahoma and similar rulings regarding reservations;

•uncertainty of estimates of oil and natural gas reserves and production;

•the cost of developing the oil and natural gas underlying our properties;

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

•our ability to identify, complete and integrate acquisitions;

•title defects in the properties in which we invest;

•the cost of inflation;

•technological advances;

•weather conditions, natural disasters and other matters beyond our control;

•general economic, business, political or industry conditions; and

•certain factors discussed elsewhere in this Quarterly Report.

Should one or more of the risks or uncertainties described in this Quarterly Report, our Annual Report or any of our other SEC filings occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

v

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	March 31,		December 31,
	2022		2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	6,213	$	20,819
Restricted cash	1		200
Accounts receivable	48,960		30,539
Prepaid expenses and other	3,301		3,145
Total current assets	58,475		54,703
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property	347,752		338,613
Evaluated property	668,952		633,138
Less accumulated depreciation, depletion, and amortization	(258,902)		(239,612)
Oil and gas properties, net	757,802		732,139
Other property and equipment	3,110		2,060
Less accumulated depreciation	(1,369)		(1,280)
Other property and equipment, net	1,741		780
Operating lease right-of-use asset	6,471		6,764
Deferred tax asset	30,468		25,308
Other assets, net	1,100		1,183
Total assets	$	856,057	$	820,877
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	15,260	$	20,473
Current operating lease liability	1,189		1,178
Total current liabilities	16,449		21,651
Long-term bank debt	93,000		93,000
Non-current operating lease liability	5,441		5,742
Other non-current liabilities	1,159		810
Equity:
Preferred stock, $0.01 par value; 50,000,000 authorized; no shares issued and outstanding at March 31, 2022 and December 31, 2021	—		—
Class A common stock, $0.01 par value; 400,000,000 authorized, 51,785,576 shares issued and 51,348,946 shares outstanding at March 31, 2022; 400,000,000 authorized, 48,796,518 shares issued and 48,359,888 shares outstanding at December 31, 2021	518		488
Class B common stock, $0.01 par value; 150,000,000 authorized, 9,181,517 shares issued and outstanding at March 31, 2022; 150,000,000 authorized, 11,371,517 shares issued and outstanding at December 31, 2021	—		—
Additional paid-in capital	698,265		634,564
Accumulated deficit	(96,394)		(105,096)
Treasury stock, at cost; 436,630 shares at March 31, 2022 and December 31, 2021	(3,527)		(3,527)
Total equity attributable to Brigham Minerals, Inc.	598,862		526,429
Non-controlling interests	141,146		173,245
Total equity	$	740,008	$	699,674
Total liabilities and equity	$	856,057	$	820,877

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

1

BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share data)

	Three Months Ended March 31,
	2022		2021
REVENUES
Mineral and royalty revenues	$	69,995	$	32,176
Lease bonus and other revenues	1,433		1,597
Total revenues	71,428		33,773
OPERATING EXPENSES
Gathering, transportation and marketing	2,003		1,733
Severance and ad valorem taxes	4,331		1,833
Depreciation, depletion, and amortization	12,313		9,367
General and administrative	5,909		5,442
Total operating expenses	24,556		18,375
INCOME FROM OPERATIONS	46,872		15,398
Interest expense, net	(914)		(267)
Other income, net	20		13
Income before income taxes	45,978		15,144
Income tax expense	6,913		3,073
NET INCOME	$	39,065	$	12,071
Less: Net income attributable to non-controlling interest	(8,083)		(3,475)
Net income attributable to Brigham Minerals, Inc. stockholders	$	30,982	$	8,596
NET INCOME PER COMMON SHARE
Basic	$	0.64	$	0.20
Diluted	$	0.62	$	0.20
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	48,439		43,515
Diluted	49,990		43,754

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

2

BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

(in thousands)

	Class A Common Stock			Class B Common Stock			Additional Paid-In Capital		Accumulated Deficit		Treasury Stock			Non-controlling Interest		Total Equity
	Shares	Amount		Shares	Amount						Shares	Amount
Balance - December 31, 2021	48,360	$	488	11,372	$	—	$	634,564	$	(105,096)	437	$	(3,527)	$	173,245	$	699,674
Issuance of common stock	800	8		—	—		20,378		—		—	—		—		20,386
Conversion of shares of Class B Common Stock to Class A Common Stock	2,190	22		(2,190)	—		34,417		—		—	—		(34,439)		—
Deferred tax asset arising from conversion of shares of Class B Common Stock to Class A Common Stock	—	—		—	—		6,203		—		—	—		—		6,203
Share-based compensation	—	—		—	—		2,703		—		—	—		—		2,703
Restricted stock forfeitures	(2)	—		—	—		—		—		—	—		—		—
Dividends and distributions declared	—	—		—	—		—		(22,280)		—	—		(5,743)		(28,023)
Issuance of common stock upon vesting of RSUs, net of shares withheld for income taxes	1	—		—	—		—		—		—	—		—		—
Net income	—	—		—	—		—		30,982		—	—		8,083		39,065
Balance - March 31, 2022	51,349	$	518	9,182	$	—	$	698,265	$	(96,394)	437	$	(3,527)	$	141,146	$	740,008

	Class A Common Stock			Class B Common Stock			Additional Paid-In Capital		Accumulated Deficit		Treasury Stock			Non-controlling Interest		Total Equity
	Shares	Amount		Shares	Amount						Shares	Amount
Balance - December 31, 2020	43,558	$	440	13,168	$	—	$	601,129	$	(92,392)	437	$	(3,527)	$	—	$	505,650
Adjustment of temporary equity to carrying value	—	—		—	—		(54,294)		—		—	—		—		(54,294)
Reclassification from temporary equity to non-controlling interest	—	—		—	—		—		—		—	—		202,496		202,496
Conversion of shares of Class B Common Stock to Class A Common Stock	112	1		(112)	—		1,720		—		—	—		(1,721)		—
Reduction in deferred tax asset arising from conversion of shares of Class B Common Stock to Class A Common Stock	—	—		—	—		(480)		—		—	—		—		(480)
Share-based compensation	—	—		—	—		3,933		—		—	—		—		3,933
Restricted stock forfeitures	(4)	—		—	—		—		—		—	—		—		—
Dividends and distributions declared	—	—		—	—		—		(11,788)		—	—		(3,447)		(15,235)
Net income	—	—		—	—		—		8,596		—	—		1,553		10,149
Balance - March 31, 2021	43,666	$	441	13,056	$	—	$	552,008	$	(95,584)	437	$	(3,527)	$	198,881	$	652,219

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

3

BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	39,065	$	12,071
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	12,313		9,367
Share-based compensation expense	1,481		2,300
Amortization of debt issuance costs	131		58
Deferred income tax expense	1,042		736
Credit losses	230		—
Changes in operating assets and liabilities:
(Increase) in accounts receivable	(18,651)		(3,908)
(Increase) decrease in other current assets	(156)		1,941
Increase (decrease) in accounts payable and accrued liabilities	6,688		(484)
Increase in other long-term liabilities	—		8
Net cash provided by operating activities	$	42,143	$	22,089
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties	(23,608)		(21,935)
Additions to other fixed assets	(1,050)		(1)
Proceeds from sale of oil and gas properties, net	7,065		—
Net cash used in investing activities	$	(17,593)	$	(21,936)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowing of long-term debt	—		12,000
Offering costs of Class A common stock	(78)		—
Dividends paid	(23,979)		(11,336)
Distribution to holders of non-controlling interest	(5,707)		(3,409)
Debt issuance costs	(44)		(1)
Payment of employee tax withholding for settlement of equity compensation awards	(9,547)		(991)
Net cash used in financing activities	$	(39,355)	$	(3,737)
Change in cash and cash equivalents and restricted cash	(14,805)		(3,584)
Cash and cash equivalents and restricted cash, beginning of period	21,019		9,144
Cash and cash equivalents and restricted cash, end of period	$	6,214	$	5,560
Supplemental disclosure of noncash activity:
Accrued capital expenditures	$	236	$	61
Capitalized share-based compensation cost	$	1,230	$	1,633
Issuance of Class A common stock for acquisitions of oil and gas properties	$	20,440	$	—
Temporary equity cumulative adjustment to redemption value	$	—	$	54,294
Supplemental cash flow information:
Cash payments for loan commitment fees and interest	$	(803)	$	(213)
Tax refunds received	$	—	$	1,024

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

4

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Business and Basis of Presentation

Description of the Business

Brigham Minerals, Inc. (together with its wholly owned subsidiaries, "Brigham Minerals," “we," "us," "our," or the "Company"), a Delaware corporation, is a holding company whose sole material asset consists of an 84.8% interest in Brigham Minerals Holdings, LLC (“Brigham LLC”), which indirectly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”). The Minerals Subsidiaries acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States.

Our portfolio is comprised of mineral and royalty interests across six of the most highly economic, liquids-rich resource plays in the continental United States, including the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP and STACK plays in the Anadarko Basin in Oklahoma, the Denver-Julesburg (“DJ”) Basin in Colorado and Wyoming and the Williston Basin in North Dakota. Our highly technical approach towards mineral acquisitions in the geologic core of top-tier resource plays has purposefully led to a concentrated portfolio covering 36 of the most highly active counties for horizontal drilling in the continental United States.

Basis of Presentation

The accompanying unaudited condensed consolidated interim financial statements of Brigham Minerals have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), except that, in accordance with the instructions to Form 10-Q, they do not include all of the notes required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim financial statements should be read in conjunction with our audited financial statements included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on February 28, 2022 (the "Annual Report"). The unaudited interim financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair representation. The results of operations for the three months ended March 31, 2022 are not necessarily indicative of the results to be expected for the entire fiscal year ending December 31, 2022. Brigham Minerals operates in one segment: oil and natural gas exploration and production.

As the primary beneficiary, Brigham Minerals consolidates the financial results of Brigham LLC and its subsidiaries and reports the interest related to the portion of the units in Brigham LLC not owned by Brigham Minerals as non-controlling interest, which will reduce net income attributable to the holders of Brigham Minerals' Class A common stock. For more information, see "Note 10—Non-controlling interest.”

2.Summary of Significant Accounting Policies    

Use of Estimates

These condensed consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the condensed consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.

The accompanying condensed consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Brigham Minerals’ year-end reserve estimates are audited by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Quarterly reserve estimates are internally generated by our in-house engineering staff.

5

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, share-based compensation costs, and revenue accruals.

Significant Accounting Policies

Significant accounting policies are disclosed in Brigham Minerals' audited consolidated financial statements and notes for the year ended December 31, 2021, presented in the Annual Report. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2022.

Accounts Receivable

Brigham Minerals routinely reviews outstanding balances, assesses the financial strength of its operators and records a reserve for amounts not expected to be fully recovered, using a current expected credit loss model. We recorded credit losses of $0.2 million for the three months ended March 31, 2022, which was included in general and administrative expenses. We did not record credit losses for the three months ended March 31, 2021.

As of March 31, 2022 and December 31, 2021, accounts receivable was comprised of the following (in thousands):

	March 31, 2022		December 31, 2021
Accounts receivable
Oil and gas sales	$	50,050	$	30,485
Reserve for credit losses	(1,150)		(995)
Other	60		1,049
Total accounts receivable	$	48,960	$	30,539

Concentration of Credit Risk and Significant Customers

Financial instruments that potentially subject Brigham Minerals to concentrations of credit risk consist of cash, accounts receivable, and its revolving credit facility. Cash and cash equivalents are held in a few financial institutions in amounts that may, at times, exceed federally insured limits. However, no losses have been incurred and management believes that counterparty risks are minimal based on the reputation and history of the institutions selected. Accounts receivable are concentrated among operators and purchasers engaged in the energy industry within the United States. Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal. Concentrations of oil and gas sales to significant customers (operators) are presented in the table below.

	Three Months Ended March 31,
	2022		2021
Pioneer Natural Resources	15	%	5	%
Chevron	12	%	4	%
Occidental Petroleum Corp	10	%	12	%
Exxon Mobil Corp	10	%	16	%
ConocoPhillips Company	6	%	12	%

Management does not believe that the loss of any customer would have a long-term material adverse effect on our financial position or the results of operations. For the three months ended March 31, 2022, we received revenues from over 140 operators with approximately 75% of revenues coming from the top ten operators on our properties. For the three months ended March 31, 2021, we received revenues from over 130 operators with approximately 69% of revenues coming from the top ten operators on our properties.

6

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3.Oil and Gas Properties

Brigham Minerals uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests are capitalized into a full cost pool. In addition, certain internal costs (or "capitalized general and administrative costs"), are also included in the full cost pool. Capitalized general and administrative costs were $3.0 million and $2.7 million for the three months ended March 31, 2022 and 2021, respectively. Capitalized costs do not include any costs related to general corporate overhead or similar activities, which are expensed in the period incurred. Oil and gas properties consisted of the following (in thousands):

	March 31, 2022		December 31, 2021
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property	$	347,752	$	338,613
Evaluated property	668,952		633,138
Total oil and gas properties, at cost	1,016,704		971,751
Less accumulated depreciation, depletion, and amortization	(258,902)		(239,612)
Total oil and gas properties, net	$	757,802	$	732,139

Capitalized costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $12.2 million and $9.3 million for the three months ended March 31, 2022 and 2021, respectively. Average depletion of proved properties was $11.29 per Boe and $11.58 per Boe for the three months ended March 31, 2022 and 2021, respectively.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (the "ceiling test"). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling test is calculated at each reporting period. The ceiling test calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. At March 31, 2022 and March 31, 2021, the SEC oil price and SEC gas price used in the calculation of the ceiling test, adjusted by area for energy content, transportation fees and regional price differentials, was $75.24 and $40.01, respectively, per barrel of oil, and $4.11 and $2.18, respectively, per MMBtu of natural gas. There were no impairment charges during the three months ended March 31, 2022 or 2021.

A decline in the SEC oil price or the SEC gas price could lead to impairment charges in the future and such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge.

4. Acquisitions and Divestitures

Echo Acquisition

On March 31, 2022, the Company completed the acquisition of approximately 1,800 net royalty acres in the Midland Basin largely operated by Pioneer Natural Resources and Endeavor Energy Resources for $14.4 million in cash, net of $0.6 million of customary closing adjustments, and 800,000 shares of the Company's Class A common stock (the "Echo Acquisition"). The cash portion of the purchase price was funded by cash on hand.

7

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table presents the acquisition consideration paid in the Echo Acquisition (in thousands, except the number of shares and price per share):

Shares of Brigham Minerals, Inc. Class A common stock issued at closing	800,000
Closing price per share of Brigham Minerals, Inc. Class A common stock on the closing date	$	25.55
Fair value of Brigham Minerals, Inc. Class A common stock issued	$	20,440
Cash consideration	14,381
Total consideration (including fair value of Brigham Minerals, Inc. Class A common stock issued)	$	34,821

The Echo Acquisition has been accounted for as an asset acquisition and the allocation of the purchase price was $16.7 million to unevaluated properties and $18.1 million to evaluated properties.

Other Acquisitions

During the three months ended March 31, 2022 and 2021, Brigham Minerals entered into a number of acquisitions of mineral and royalty interests from various sellers in Texas, Oklahoma, Colorado, New Mexico, and North Dakota, as reflected in the tables below (in thousands).

	Oil and Gas Properties Acquired				Cash Consideration
	Evaluated		Unevaluated
Quarter Ended March 31, 2022	$	4,562	$	4,340	$	8,902
Quarter Ended March 31, 2021	$	9,073	$	12,776	$	21,849

The change in the oil and natural gas property balance is comprised of payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative expenses that for the three months ended March 31, 2022 and 2021 were funded with our retained operating cash flow, proceeds from asset sales and our revolving credit facility (as hereinafter defined).

Divestitures

During the three months ended March 31, 2022, Brigham Minerals divested certain non-core, mostly undeveloped acreage in Oklahoma and received cash proceeds of $7.1 million, net of customary closing adjustments.

5. Revenue From Contracts With Customers

Mineral and royalty revenues

Mineral and royalty revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company's oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the Company's contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 60 days of the month of delivery, however this can extend approximately six months after initial production from the well as our team works with the operator to put us into pay status. The Company's contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, Brigham Minerals recognizes revenue from oil and natural gas sales using the allocation exception for variable consideration in ASC 606.

8

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the three months ended March 31, 2022 and 2021, the disaggregated revenues from sales of oil, natural gas and NGLs are as follows (in thousands):

	Three Months Ended March 31,
	2022		2021
Oil sales	$	50,688	$	22,813
Natural gas sales	10,312		5,437
NGL sales	8,995		3,926
Total mineral and royalty revenues	$	69,995	$	32,176

Lease bonus and other income

Brigham Minerals also earns revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. The Company recognizes lease bonus revenues when the lease agreement has been executed, payment has been received, and the Company has no further obligation to refund the payment. At the time Brigham Minerals executes the lease agreement, Brigham Minerals expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that Brigham Minerals has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. Brigham Minerals also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and we have no further obligation to refund the payment. Right-of-way payments are recorded by the Company when the agreement has been executed, payment is determined to be collectable, and the Company has no further obligation to refund the payment.

Allocation of transaction price to remaining performance obligations

Mineral and royalty revenues

Brigham Minerals’ right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.

Lease bonus and other income

Given that Brigham Minerals does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, Brigham Minerals does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

Brigham Minerals records revenue in the month production is delivered to the purchaser. As a non-operator, Brigham Minerals has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, Brigham Minerals is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the accounts receivable line item in the accompanying condensed consolidated balance sheets. The difference between the Company’s estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three months ended March 31, 2022 and 2021, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

9

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Fair Value Measurements

We classify financial assets and liabilities that are measured and reported at fair value on a recurring basis using a hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We classify the inputs used to measure fair value into the following hierarchy:

•    Level 1: Inputs based on quoted market prices in active markets for identical assets or liabilities at the measurement date.

•    Level 2: Inputs based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable and can be corroborated by observable market data.

•    Level 3: Inputs that reflect management’s best estimates and assumptions of what market participants would use in pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the valuation of the instruments.

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer would be reported at the beginning of the period in which the change occurs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 2022 and December 31, 2021.

Brigham Minerals had no transfers into or out of Level 1 and no transfers into or out of Level 2 for the three months ended March 31, 2022 and March 31, 2021.

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

Certain non-financial assets and liabilities, such as assets and liabilities acquired in a business combination, are measured at fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and include factors such as estimates of economic reserves, future commodity prices and risk-adjusted discount rates, and are classified within Level 3.

Fair Value of Other Financial Instruments

The carrying value of cash, trade and other receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. The carrying amount of debt outstanding pursuant to our revolving credit facility approximates fair value as interest rates on the revolving credit facility approximate current market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.

7. Long-Term Debt

Revolving Credit Facility

On May 16, 2019, Brigham Resources, LLC ("Brigham Resources"), a wholly-owned subsidiary of Brigham LLC, entered into a credit agreement with Wells Fargo Bank, N.A., as administrative agent (the "Administrative Agent") for the various lenders from time to time party thereto, providing for a revolving credit facility (our "revolving credit facility"). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is collateralized by a lien on a substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including a substantial portion of their respective royalty and mineral properties.

10

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On July 7, 2021, Brigham Resources entered into the Third Amendment to the credit agreement (the "Third Amendment"). The Third Amendment, among other things, evidenced an increase of the borrowing base and elected commitments under the prior credit agreement from $135.0 million to $165.0 million and the addition of leverage (maximum 3.00x) and liquidity (minimum 10% of total net revolving commitments) conditions to Brigham Resources’ ability to pay dividends or distributions (other than permitted tax distributions) to the owners of its equity interests.

On December 15, 2021, Brigham Resources entered into the Fourth Amendment to the credit agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, evidenced a further increase of the borrowing base and elected commitments under the prior credit agreement from $165.0 million to $230.0 million.

Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination semi-annually. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. Brigham Resources can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The weighted average interest rate for the three months ended March 31, 2022 was 2.96%. As of March 31, 2022, the borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million, resulting in $137.0 million available for future borrowings.

Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our borrowing base. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions.

Our revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the Administrative Agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Our revolving credit facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject to Consolidated Total Leverage Ratio and liquidity thresholds) and investments. In addition, our revolving credit facility requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00. As of March 31, 2022, we were in compliance with all covenants in accordance with our revolving credit facility.

11

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Leases

The Company enters into leasing transactions in which the Company is the lessee. The Company's lease contracts are generally for office buildings, and office equipment. The Company performed evaluations of its contracts and determined it has only operating leases.

In July 2019, the Company entered into a lease agreement for its corporate headquarters located in Austin, TX (the “Bridgepoint Lease”). The Bridgepoint Lease includes approximately 29,546 square feet and commenced in July 2019, with an expiration on June 30, 2027. The Bridgepoint Lease includes lease and non-lease components that we account for as a single lease component as an accounting policy election. The Bridgepoint Lease requires monthly lease payments that may be subject to annual increases throughout the lease term and also includes renewal options at the election of the Company to renew or extend the lease for two, consecutive, five-year lease terms. This optional period has not been included in the lease term in the determination of the operating lease right-of-use-assets or operating lease liabilities associated with these leases as the Company did not consider it reasonably certain it would exercise the options. Since the Bridgepoint Lease does not contain an implicit rate, the Company used the incremental borrowing rate of 2% as the discount rate to calculate present value of lease payments. Rent expense on operating leases is recognized over the term of the lease on a straight-line basis. Rent expense for the three months ended March 31, 2022 and 2021 was $0.3 million in each period.

The Company also enters into leasing transactions in which the Company is the lessor, primarily through land easements. The Company performed evaluations on all term-based land easement payments received during the three months ended March 31, 2022 and determined that all such payments were immaterial in the aggregate.

The following table summarizes the Company’s recognition of its operating lease (in thousands):

	Classification	March 31, 2022
Assets
Operating	Operating lease right-of-use assets	$	6,471
Liabilities
Current:
Operating	Current operating lease liability	$	1,189
Non-current:
Operating	Non-current operating lease liability	$	5,441

The table below presents the maturity of the Company’s liabilities under the Bridgepoint Lease as of March 31, 2022 (in thousands):

	Commitment
2022 (remainder of)	$	975
2023	1,319
2024	1,340
2025	1,360
2026	1,383
Thereafter	582
Total lease payments	6,959
Less imputed interest	(329)
Total lease liabilities	$	6,630

12

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Equity

Class A Common Stock

Brigham Minerals had approximately 51.3 million shares of its Class A common stock outstanding as of March 31, 2022. Holders of Class A common stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s Board of Directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities.

Class B Common Stock

Brigham Minerals had approximately 9.2 million shares of its Class B common stock outstanding as of March 31, 2022. Holders of the Class B common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of Class A common stock and Class B common stock generally vote together as a single class on all matters presented to Brigham Minerals’ stockholders for their vote or approval. Holders of Class B common stock do not have any right to receive dividends or distributions upon a liquidation or winding up of Brigham Minerals.

Treasury Stock

As of March 31, 2022, there were 436,630 shares of Class A common stock held in treasury.

Earnings per Share

Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. Brigham Minerals uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding shares of Class B common stock (and corresponding units of Brigham LLC ("Brigham LLC Units")), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding RSAs, RSUs, PSUs (each as defined in "Note 11—Share-Based Compensation") and unvested Incentive Units. Brigham Minerals does not use the two-class method because the Class B common stock and the unvested share-based awards are nonparticipating securities.

For the three months ended March 31, 2022 and 2021, the Incentive Units and shares of Class B common stock were not recognized in dilutive EPS calculations as the effects would have been antidilutive. As of March 31, 2021, there were 1,187,811 shares related to PSUs (based on target), that could vest in the future dependent on predetermined market conditions. These units were not included in the computation of EPS for the three months ended March 31, 2021, because the performance goals had not been met, assuming the end of the reporting period was the end of the contingency period.

13

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table reflects the allocation of net income to common stockholders and EPS computations for the period indicated based on a weighted average number of common stock outstanding for the period (in thousands, except per share data):

	Three Months Ended March 31,
	2022		2021
Basic EPS
Numerator:
Basic net income attributable to Brigham Minerals, Inc. stockholders	$	30,982	$	8,596
Denominator:
Basic weighted average shares outstanding	48,439		43,515
Basic EPS attributable to Brigham Minerals, Inc. stockholders	$	0.64	$	0.20
Diluted EPS
Numerator:
Basic net income attributable to Brigham Minerals, Inc. stockholders	$	30,982	$	8,596
Diluted net income attributable to Brigham Minerals, Inc. stockholders	$	30,982	$	8,596
Denominator:
Basic weighted average shares outstanding	48,439		43,515
Effects of dilutive securities:
Unvested equity awards	1,551		239
Diluted weighted average shares outstanding	49,990		43,754
Diluted EPS attributable to Brigham Minerals, Inc. stockholders	$	0.62	$	0.20

10. Non-controlling interest

Non-controlling interest represents the 15.2% interest in the units of Brigham LLC not owned by Brigham Minerals, as of March 31, 2022. Each share of Class B common stock does not have any economic rights but entitles its holder to one vote on all matters to be voted on by our stockholders generally, and holders of Brigham LLC Units (and Class B common stock) have a redemption right into shares of Class A common stock. Under the Brigham LLC Agreement, each Brigham LLC Unit Holder, subject to certain limitations, has a right (the "Redemption Right") to cause Brigham LLC to acquire all or a portion of its Brigham LLC Units for, at Brigham LLC’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Brigham LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. We will determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Brigham LLC Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Brigham Minerals (instead of Brigham LLC) will have a call right to, for administrative convenience, acquire each tendered Brigham LLC Unit directly from the redeeming Brigham LLC Unit Holder for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash (the "Call Right"). The decision to make a cash payment upon a Brigham LLC Unit Holder's exercise of its Redemption Right is required to be made by the Company's directors who are independent under Section 10A-3 of the Securities Act and do not hold any Brigham LLC Units subject to such redemption. In connection with any redemption of Brigham LLC Units pursuant to the Redemption Right or acquisition pursuant to our Call Right, the corresponding number of shares of Class B common stock will be cancelled.

14

BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Non-controlling interest is recorded at its carrying value. For the period from December 31, 2021 to March 31, 2022, the Company recorded adjustments to the value of non-controlling interest as presented in the table below (in thousands):

	Non-controlling interest
Balance - December 31, 2021	$	173,245
Conversion of Class B common stock to Class A common stock	(34,439)
Net income attributable to non-controlling interest	8,083
Distribution to holders of non-controlling interest declared	(5,743)
Balance - March 31, 2022	$	141,146

11. Share-Based Compensation

Long Term Incentive Plan

In connection with the IPO, Brigham Minerals adopted the Brigham Minerals, Inc. 2019 Long Term Incentive Plan (“LTIP”) for employees, consultants and directors who perform services for Brigham Minerals. The LTIP provides for issuance of awards based on shares of Class A common stock. Brigham Minerals has issued restricted stock awards ("RSAs"), restricted stock units subject to time-based vesting ("RSUs") and restricted stock units subject to performance-based vesting ("PSUs") under the LTIP. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by Brigham Minerals including shares purchased on the open market. A total of 5,999,600 shares of Class A common stock have been authorized for issuance under the LTIP. At March 31, 2022, 2,501,017 shares of Class A common stock remained available for future grants. Currently, all RSAs, RSUs and PSUs granted under the LTIP are entitled to receive dividends (in the case of RSAs) or have dividend equivalent rights (“DERs”), which entitle holders of RSUs and PSUs to the same dividend value per share as holders of the Company's Class A common stock. Such dividends and DERs are subject to the same vesting and other terms and conditions as the corresponding unvested RSAs, RSUs, and PSUs. Dividends and DERs are accumulated and paid when the underlying shares vest. The fair value of the RSA awards granted with the right to receive dividends and RSU awards granted with the right to receive DERs are generally based on the trading price of the Company’s Class A common stock as of the date of grant. Brigham Minerals accounts for the awards granted under the LTIP as compensation cost measured at the fair value of the award on the date of grant. Brigham Minerals accounts for forfeitures as they occur.

The Company has granted RSAs to certain employees, which are grants of shares of Class A common stock subject to a risk of forfeiture and restrictions on transferability. The share-based compensation expense of such RSAs was determined using the closing price of Class A common stock on April 23, 2019, the date of grant, of $21.25. On April 23, 2019, 312,189 RSAs were granted and 152,742 RSAs held by former employees of the Company vested immediately. The RSAs generally vested in one-third increments on each of April 23, 2020, 2021 and 2022.

The following table summarizes activity related to RSAs for the three months ended March 31, 2022.

	Restricted Stock Awards
	Number of RSAs	Grant Date Fair Value
Unvested at January 1, 2022	30,433	$	21.25
Forfeited	(1,723)	$	21.25
Unvested at March 31, 2022	28,710	$	21.25

The Company has granted RSUs to certain employees and directors, which represent the right to receive shares of Class A common stock at the end of the vesting period in an amount equal to the number of RSUs that vest. The RSUs issued to employees generally vest in one-third increments over a three-year period and RSUs issued to directors vest in one year from the date of grant. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient ceases providing services to Brigham Minerals prior to the date the award vests. The share-based compensation cost of such RSUs was determined using the closing price on the applicable date of grant, which is then applied to the total number of RSUs granted. Brigham Minerals accounts for forfeitures as they occur. During the three months ended March 31, 2022, the Company granted

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

345,624 RSUs. The share-based compensation expense of such RSUs was determined using the weighted-average grant date fair value of $24.26.

The following table summarizes activity related to RSUs for the three months ended March 31, 2022.

	Restricted Stock Units
	Number of RSUs	Weighted-Average Grant Date Fair Value
Unvested at January 1, 2022	553,976	$	16.55
Granted	345,624	$	24.26
Vested	(781)	$	16.49
Forfeited	(67,942)	$	16.62
Unvested at March 31, 2022	830,877	$	19.75

The Company has granted PSUs to certain officers and managers, which vest based on continuous employment and satisfaction of a market condition based on the absolute total stockholder return of the Company’s common stock, including paid dividends, over an approximate three-year performance period. The terms and conditions of the PSUs allow for vesting of the awards ranging between 0% (or forfeiture) and 200% of target. In addition, the number of PSUs earned may be adjusted based on our relative TSR as compared to a benchmarking peer group over the three-year performance period. Expense related to these PSUs is recognized on a straight-line basis over the length of the applicable performance period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The grant date fair value of such PSUs was determined using a Monte Carlo simulation model that utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award to calculate the fair value of the award. Expected volatilities in the model were estimated on the basis of historical volatility of a group of publicly traded oil and gas companies with a performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.

The following table summarizes activity related to PSUs for the three months ended March 31, 2022:

	Performance-Based Restricted Stock Units
	Target PSUs	Grant Date Fair Value
Unvested at January 1, 2022	906,643	$	11.94
Granted	295,846	$	11.93
Forfeited	(58,938)	$	13.41
Unvested at March 31, 2022	1,143,551	$	11.86

During the three months ended March 31, 2022, the Company granted 295,846 PSUs. The share-based compensation expense of such PSUs was determined using the valuation date of March 20, 2022, the date of grant, with a fair value of $11.93. In addition, no PSUs became vested during the three months ended March 31, 2022.

Short Term Incentive Plan

During 2022, the Company implemented a short term incentive plan (the “STIP”) for executives and certain other employees who perform services for the Company. The STIP is based on quantitative and qualitative metrics that are key drivers of shareholder value.

Each STIP participant was assigned a target award opportunity expressed as a percentage of base salary and the awards allow for attainment ranging between 0% and 150% of target. Award attainment is based on the achievement of various financial, operational and other strategic metrics.

If earned, the STIP awards will be paid in cash at the completion of the plan year for all employees other than the CEO. The CEO's STIP awards will be paid out in the form of shares of our Class A common stock, rather than cash, with such award subject

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to a one-year vesting period. As the STIP awards to be settled in shares of our Class A common stock will consist of a variable number of shares based on the award attainment at the completion of the plan year and the fair market value of our Class A common stock, we will initially account for these awards as liabilities with performance conditions. Once the number of shares to be issued has been fixed, the awards will be reclassified to equity.

Expense for awards with performance conditions is only recognized when achievement of the performance target is deemed probable. The expense to be recognized is based on the Company’s best estimate of probable attainment at the end of each reporting period prorated for the portion of the requisite service period rendered.

The target attainment for the STIP awards for the year ended December 31, 2022 is $2.4 million, of which $0.5 million is expected to be settled in shares of the Company's Class A common stock. During the three months ended March 31, 2022, the Company accrued $0.5 million related to the STIP awards.

Share-Based Compensation Expense

Share-based compensation expense is included in general and administrative expense in the Company's condensed consolidated statements of operations included within this Quarterly Report. Share-based compensation expense recorded for each type of share-based compensation award for the three months ended March 31, 2022 and 2021 is summarized in the table below (in thousands).

	Three Months Ended March 31,
	2022		2021
Incentive units (1)	$	178	$	178
RSAs (1)	125		134
RSUs (1)	1,426		2,542
PSUs (2)	974		1,079
STIP awards (3)	8		—
Capitalized share-based compensation (4)	(1,230)		(1,633)
Total share-based compensation expense	$	1,481	$	2,300

(1)Share-based compensation expense relating to Incentive Units, RSAs and RSUs with ratable vesting is recognized on a straight-line basis over the requisite service period for the entire award.

(2)Share-based compensation expense relating to PSUs with cliff-vesting is recognized on a straight-line basis over the performance period for the entire award.

(3)Share-based compensation expense relating to STIP awards to be settled in shares of our Class A common stock is recognized on a straight-line basis over the requisite service period for the entire award.

(4)During the three months ended March 31, 2022, Brigham Minerals capitalized $0.6 million of share-based compensation cost to unevaluated property and $0.6 million of share-based compensation cost to evaluated property. During the three months ended March 31, 2021, Brigham Minerals capitalized $0.9 million of share-based compensation cost to unevaluated property and $0.7 million and of share-based compensation cost to evaluated property.

Future Share-Based Compensation Expense

The following table reflects the future share-based compensation expense expected to be recorded for the share-based compensation awards that were outstanding at March 31, 2022, a portion of which will be capitalized (in thousands):

	Incentive Units		RSAs		RSUs		PSUs		STIP Awards		Total
2022	$	356	$	38	$	5,844	$	3,548	$	202	$	9,988
2023	—		—		5,257		3,877		268		9,402
2024	—		—		2,769		1,179		57		4,005
2025	—		—		598		254		—		852
Total	$	356	$	38	$	14,468	$	8,858	$	527	$	24,247

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Income Taxes

The Company evaluates and updates its annual effective income tax rate on a quarterly basis under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make comparisons not meaningful. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs.

Income tax expense was as follows for the periods indicated (in thousands, except for tax rate):

	Three Months Ended March 31,
	2022			2021
Income tax expense	$	6,913		$	3,073
Effective tax rate	15.0		%	20.3		%

Total income tax expense for the three months ended March 31, 2022 and 2021 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of excess tax benefits resulting from vesting of equity awards, non-controlling interest, state taxes (net of the anticipated federal benefit), share-based compensation expense, and percentage depletion in excess of basis. The effective tax rate for the three months ended March 31, 2022 and 2021 reflects Brigham Minerals' ownership interest in Brigham LLC of 84.8% and 77.0%, respectively, at the end of each period.

13. Contingencies

Brigham Minerals may, from time to time, be a party to certain lawsuits and claims arising in the ordinary course of business. The outcome of such lawsuits and claims cannot be estimated with certainty and management may not be able to estimate the range of possible losses. Brigham Minerals records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Minerals had no reserves for contingencies at March 31, 2022 and December 31, 2021.

14. COVID-19 Pandemic

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, demand for the commodities produced by the oil and natural gas industry and commodity prices have improved substantially from historic lows in 2020. However, the duration of the COVID-19 pandemic and potential future impact to our business and industry continues to be unpredictable and dynamic.

15. Subsequent Events

On May 1, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.60 per share of Class A common stock payable on May 27, 2022, to stockholders of record at the close of business on May 20, 2022.

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

Brigham Minerals, Inc. (the "Company," "we," "us," or "our") is the managing member of Brigham Minerals Holdings, LLC (“Brigham LLC”) and is responsible for all operational, management and administrative decisions related to Brigham LLC and its operating subsidiaries’ business. The following discussion and analysis should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “Annual Report”), as well as the accompanying unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q (this "Quarterly Report").

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved, probable and possible reserves, mineral acquisition capital, economic and competitive conditions, including those resulting from the ongoing COVID-19 pandemic and the current conflict between Russia and Ukraine, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report and in our Annual Report, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Brigham Minerals was formed to acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our stockholders through (i) the growth of our free cash flow generated from our existing mineral portfolio and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of March 31, 2022, we owned 93,465 net royalty acres across 36 counties within the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the Denver-Julesburg ("DJ") Basin in Colorado and Wyoming and the Williston Basin in North Dakota.

Financial and Operational Overview:

•Our production volumes of 12,031 Boe/d (71% liquids, 51% oil) for the three months ended March 31, 2022 increased 31% compared to the three months ended December 31, 2021 and 35% compared to the three months ended March 31, 2021.

•Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales for the three months ended March 31, 2022 increased 49% to $70.0 million compared to the three months ended December 31, 2021 due to a 16% increase in realized commodity pricing and 31% higher production volumes and increased 118% compared to the three months ended March 31, 2021 due to a 61% increase in realized commodity pricing and a 35% increase in production volumes.

•Our net income for the three months ended March 31, 2022 was $39.1 million compared to $21.7 million for the three months ended December 31, 2021 and $12.1 million for the three months ended March 31, 2021.

•Adjusted EBITDA and Adjusted EBITDA ex lease bonus for the three months ended March 31, 2022 were $60.7 million and $59.2 million, respectively, and increased 53% and 52%, respectively, as compared to the three months ended December 31, 2021 and increased 124% and 133%, respectively, as compared to the three months ended March 31, 2021. Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparable measure calculated and presented in accordance with GAAP, please read "How We Evaluate our Operations—Non-GAAP Financial Measures."

•On May 1, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.60 per share of Class A common stock payable on May 27, 2022 to stockholders of record at the close of business on May 20, 2022.

•As of March 31, 2022, Brigham Minerals had a cash balance of $6.2 million and $137.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of $143.2 million. Associated with the Company's late-May semi-annual borrowing base redetermination under its revolving credit facility, the Administrative Agent has

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indicated a preliminary recommended borrowing base increase to $300.0 million. Pro-forma for the anticipated increase in the borrowing base, the Company would have had total liquidity of $213.2 million as of March 31, 2022.

Echo Acquisition

On March 31, 2022, the Company completed the acquisition of approximately 1,800 net royalty acres in the Midland Basin largely operated by Pioneer Natural Resources and Endeavor Energy Resources for $14.4 million in cash, net of $0.6 million of customary closing adjustments, and 800,000 shares of Class A common stock. The combined cash consideration and acquisition shares issued totaled $34.8 million.

Market Environment, COVID-19 and Russia/Ukraine Conflict

The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, demand for the commodities produced by the oil and natural gas industry and commodity prices have continued to improve substantially from historic lows in 2020. However, the duration of the COVID-19 pandemic and potential future impact to our business and industry continues to be unpredictable and dynamic.

In connection with the previously mentioned COVID-19 pandemic and resulting market and commodity price challenges experienced during 2020, we saw reduced levels of potential acquisition opportunities. With an improvement in commodity prices in 2021 and into 2022, along with our financial strength, we believe we are well positioned to capture attractive opportunities that will generate stockholder value. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations, proceeds from portfolio rationalizations and borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy.

Additionally, in February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. The current conflict between Russia and Ukraine may also have the effect of heightening many of the risks disclosed in our Annual Report, any of which could have a material adverse effect on our business and results of operations. Such risks include, but are not limited to, adverse effects on global macroeconomic conditions, increased volatility in the price and demand for oil and natural gas, and disruptions in global supply chains.

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Operational Update

Mineral and Royalty Interest Ownership Update

During the first quarter 2022, the Company completed eight ground game transactions, including the Echo Acquisition described above, acquiring approximately 2,100 net royalty acres (standardized to a 1/8th royalty interest) and deploying $43.7 million in capital, primarily in the Permian Basin. As of March 31, 2022, the Company owned roughly 93,465 net royalty acres, encompassing 13,384 gross (108.5 net) undeveloped horizontal locations, across 36 counties in what the Company views as the cores of the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota. The Company also divested 985 net royalty acres in the Anadarko Basin generating $7.1 million in cash proceeds, net of customary closing adjustments.

The table below summarizes the Company’s mineral and royalty interest ownership at the dates indicated.

	Delaware	Midland	SCOOP	STACK	DJ	Williston	Other (2)	Total
Net Royalty Acres
March 31, 2022 (1)	29,875	8,265	11,435	8,195	24,740	8,185	2,770	93,465
December 31, 2021	29,735	6,335	11,435	8,195	24,740	8,155	3,780	92,375
Acres Added and (Sold) Q/Q	140	1,930	—	—	—	30	(1,010)	1,090
% Added and (Sold) Q/Q	—%	30%	—%	—%	—%	—%	(27)%	1%

(1)March 31, 2022 NRA totals include division order interest ("DOI") adjustments relative to prior quarters; DOI adjustments are bucketed within Other.

(2)Other includes (i) mostly Anadarko acreage (non-SCOOP/STACK) and (ii) DOI adjustments.

Operating Activity Update

DUC Conversions

The Company identified approximately 167 gross (2.7 net) DUCs converted to production during the first quarter 2022, which represented 37% of its net DUCs (20% of its gross DUCs) in inventory as of fourth quarter 2021. First quarter 2022 gross DUC and PDP conversion waterfalls are summarized in the charts below:

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Drilling Activity

During the first quarter 2022, the Company identified 238 gross (2.1 net) wells spud on its mineral position, which represents a 113% increase in net well drilling activity relative to fourth quarter 2021. Brigham’s gross and net wells spud activity per quarter is summarized in the chart below:

DUC and Permit Inventory

Brigham Minerals ended the first quarter 2022 with 7.1 net DUCs and 4.6 net permits versus 7.4 net DUCs and 5.5 net permits as of fourth quarter 2021. Brigham Minerals' gross and net DUC and permit inventory as of March 31, 2022 by basin is outlined in the table below:

	Development Inventory by Basin (1)
	Delaware	Midland	SCOOP	STACK	DJ	Williston	Other	Total
Gross Inventory
DUCs	224	275	37	17	216	147	18	934
Permits	303	100	6	—	213	216	8	846
Net Inventory
DUCs	2.2	1.7	0.2	0.1	2.5	0.3	0.1	7.1
Permits	2.3	0.3	—	—	1.4	0.5	—	4.6

(1)    Individual amounts may not total due to rounding.

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Regulatory Update

Muscogee (Creek) Nation Reservation

On July 9, 2020, the U.S. Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the Court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablished. State district courts in Oklahoma, applying the analysis in U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation, have ruled that the Cherokee, Chickasaw, Seminole, Quapaw and Choctaw reservations likewise have not been disestablished. Other nations, such as the Osage Nation, have also sought to have findings of disestablishment overturned. While we cannot predict the full extent to which civil jurisdiction may be affected, the ruling could adversely affect title to our mineral interests, to the extent they are found to be located within reservation areas, and significantly impact laws and regulations to which we and our operators and interests are subject in Oklahoma, such as taxation, environmental regulation, and the permitting and siting of energy assets.

On October 1, 2020, the Environmental Protection Agency (the "EPA") granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to many areas of Indian Country within Oklahoma, effectively extending Oklahoma’s authority for existing EPA-approved regulatory programs to lands within Oklahoma previously under the jurisdiction of the State before the U.S. Supreme Court’s ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw and reconsider the October 2020 decision. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from the EPA.

Separately, in 2021, the U.S. Department of the Interior subsequently used the ruling in McGirt to find that Oklahoma could not keep jurisdiction over surface coal mining on the Muscogee (Creek) Nation’s lands. The State of Oklahoma has petitioned the U.S. Supreme Court to overturn this determination and find that McGirt either is limited to federal criminal matters or was incorrectly decided. Several other suits have been filed in state and federal courts regarding the appropriate scope of McGirt, including a stayed proceeding before the Oklahoma Supreme Court regarding the Oklahoma Corporation Commission’s authority to issue drilling permits on the Muscogee (Creek) reservation. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved. We will continue to monitor developments concerning these matters.

Dakota Access Pipeline (“DAPL”)

On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of DAPL’s easement from the “Corps” and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. Following the denial of a rehearing en banc, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On February 22, 2022, the U.S. Supreme Court declined to consider Dakota Access' appeal. The pipeline continues to operate pending completion of the Environmental Impact Statement which the Corps now estimates will be complete by the end of 2022. We cannot determine when or how future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, transportation costs for crude oil will likely increase in the Williston Basin, and the operators of our properties in the Williston Basin may choose to shut in wells if they are unable to connect those wells to other pipelines or obtain sufficient capacity on other pipelines at an effective cost, both of which may adversely impact our revenues and future production from our properties in the Williston Basin.

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Implementation of Colorado SB 19-181 (“SB 181”)

In November 2020, the Colorado Oil and Gas Conservation Committee ("COGCC"), as part of SB 181’s mandate for the COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions, effective January 15, 2021, to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. The Colorado Department of Public Health and the Environment also recently finalized rules related to the control of emissions from certain pre-production activities; namely, the curbing of methane emissions from oil and gas operations to include setting methane emissions limits per 1,000 Boe produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of SB 181 could adversely impact our revenues and future production from our properties.

Proposed SEC Climate Disclosure Rules

On March 21, 2022, the U.S. Securities and Exchange Commission proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our operators could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.

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, natural gas and NGLs produced;

•number of rigs on location, permits, spuds, completions and wells turned-in-line;

•commodity prices; and

•Adjusted EBITDA and Adjusted EBITDA ex lease bonus.

Volumes of Oil, Natural Gas and NGLs Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various resource plays that comprise our portfolio of mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Number of Rigs on Location, Permits, Spuds, Completions and Wells Turned-In-Line

In order to track and assess the performance of our assets, we monitor and analyze the number of permits, rigs, spuds, completions and wells on production that are applicable to our mineral and royalty interests in an effort to evaluate near-term production growth from the various basins and resource plays that comprise our asset base.

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Commodity Prices

Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. As of March 31, 2022, the posted price for oil was $100.53 per barrel and the Henry Hub spot market price of natural gas was $5.46 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically as well as the amount of capital they are willing to spend.

The prices we receive for oil, natural gas and NGLs vary by geographical area. The relative prices of these products are determined by factors affecting global and regional supply and demand dynamics, such as economic and geopolitical conditions, including the current conflict between Russia and Ukraine, the effects of health pandemics such as COVID-19, production levels, availability of transportation and storage, 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 NYMEX prices are referred to as differentials. All of 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 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 crude 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 crude 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 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 that 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 is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Oil and gas properties

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (the "ceiling test"). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling test is calculated at each reporting period. The ceiling test calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. As of March 31, 2022 and March 31, 2021, the SEC oil price and SEC gas price used in

25

the calculation of the ceiling test were $75.24 and $40.01, respectively, per barrel for oil, and $4.11 and $2.18, respectively, per MMBtu for natural gas. There were no impairment charges during the three months ended March 31, 2022 and 2021.

A decline in the SEC oil price or the SEC gas price could lead to impairment charges in the future and such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development activities, production data, economics and other factors, we may be required to write down the carrying value of our properties in future periods. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during sustained periods of low commodity prices. In addition, impairments could occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.

Hedging

We may enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our cash flow 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 cash flows we ultimately realize. Historically, we have only entered into minimal 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. 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 may partially mitigate the effect of lower prices on our future revenue.

Our revolving credit facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves of oil and natural gas, calculated separately, for the lesser of the remaining time until maturity or up to 60 months in the future. We had no natural gas or oil derivative contracts in place as of March 31, 2022 and December 31, 2021.

Non-GAAP Financial Measures

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

We define Adjusted EBITDA as Net Income before depreciation, depletion and amortization, share-based compensation expense, interest expense, and income tax expense, less other income. We define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus and other revenues we receive due to the unpredictability of timing and magnitude of the revenue.

Adjusted EBITDA and Adjusted EBITDA ex lease bonus do not represent and should not be considered alternatives to, or more meaningful than, net income or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Adjusted EBITDA and Adjusted EBITDA ex lease bonus have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus may differ from computations of similarly titled measures of other companies.

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The following table presents a reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to the most directly comparable GAAP financial measure for the periods indicated (in thousands):

	Three Months Ended
	March 31, 2022		December 31, 2021		March 31, 2021
Reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to Net Income:
Net Income	$	39,065	$	21,718	$	12,071
Add:
Depreciation, depletion, and amortization	12,313		9,548		9,367
Share-based compensation expense	1,481		2,166		2,300
Interest expense, net	914		596		267
Income tax expense	6,913		5,536		3,073
Less:
Other income, net	20		2		13
Adjusted EBITDA	$	60,666	$	39,562	$	27,065
Less:
Lease bonus and other revenues	1,433		624		1,597
Adjusted EBITDA ex lease bonus	$	59,233	$	38,938	$	25,468

Sources of Our Revenues

Our revenues are primarily derived from the mineral and royalty payments we receive from our operators based on the sale of oil, natural gas and NGLs produced from our properties, as well as from lease bonus payments. Mineral and royalty revenues may vary significantly from period to period as a result of changes in volumes of production sold by our operators, production mix and commodity prices. Lease bonus and other revenues vary from period to period as a result of leasing activity on our mineral interests.

The following table presents the breakdown of our revenues for the following periods:

	Three Months Ended
	March 31, 2022		December 31, 2021		March 31, 2021
Royalty revenues
Oil sales	71	%	69	%	68	%
Natural gas sales	14	%	16	%	15	%
NGL sales	13	%	14	%	12	%
Total royalty revenue	98	%	99	%	95	%
Lease bonus and other revenues	2	%	1	%	5	%
Total revenues	100	%	100	%	100	%

Principle Components of Our Cost Structure

The following is a description of the principle components of our cost structure. However, as an owner of mineral and royalty interests, we are not obligated to fund drilling and completion capital expenditures to bring a horizontal well on line, lease operating expenses to produce our oil, natural gas and NGLs nor the plugging and abandonment costs at the end of a well’s economic life. All of the aforementioned costs are borne entirely by the exploration and production companies that have leased our mineral and royalty interests.

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Gathering, Transportation and Marketing Expenses

Gathering, transportation and marketing expenses include the costs to process and transport our production to applicable sales points. Generally, the terms of the lease governing the development of our properties permits the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

Severance and Ad Valorem Taxes

Severance taxes are paid on sold oil, natural gas or NGLs based on either a percentage of revenues from production sold or the number of units of production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues, which is driven by our production volumes and prices received for our oil, natural gas and NGLs. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the state or local government’s appraisal of the value of our oil, natural gas and NGL properties, which also trend with anticipated production, as well as oil, natural gas and NGL prices. Rates, methods of calculating property values and timing of payments vary across the different counties in which we own mineral and royalty interests.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization ("DD&A") is the systematic expensing of the capitalized costs incurred to acquire evaluated oil and natural gas properties. We use the full cost method of accounting, and, as such, all acquisition-related costs to acquire evaluated properties are capitalized and amortized in aggregate based on the estimated economic productive lives of our properties. Depletion is the expense recorded based on the cost basis of our properties and the volume of hydrocarbons extracted during each respective period, calculated on a units-of-production basis. Estimates of proved reserves are a major component of our calculation of depletion. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports. The year-end reserve reports are audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers.

General and Administrative

General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our staff, share-based compensation expense, costs of maintaining our headquarters, costs of managing our properties, annual and quarterly reports to stockholders, tax return preparation, independent and internal auditor fees, investor relations activities, incremental director and officer liability insurance costs, independent director compensation, other fees for professional services and legal compliance.

Interest Expense

We finance a portion of our working capital requirements and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest and loan commitment fees paid to the lenders under our debt arrangements (currently, our revolving credit facility) and amortization of debt issuance costs in interest expense.

Income Tax Expense

Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of up to 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A portion of our mineral and royalty interests are located in Texas basins.

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Results of Operations

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

The following table provides the components of our revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes (dollars in thousands, except for realized prices and unit expenses):

	Three Months Ended
	March 31, 2022		December 31, 2021		Variance
Production:
Oil (MBbls)	552		432		120		28	%
Natural gas (MMcf)	1,868		1,445		423		29	%
NGLs (MBbls)	220		171		49		29	%
Equivalents (MBoe)	1,083		844		239		28	%
Equivalents per day (Boe/d)	12,031		9,170		2,861		31	%
Revenues:
Oil sales	$	50,688	$	32,769	$	17,919	55	%
Natural gas sales	10,312		7,620		2,692		35	%
NGL sales	8,995		6,656		2,339		35	%
Total mineral and royalty revenue	$	69,995	$	47,045	$	22,950	49	%
Lease bonus and other revenue	1,433		624		809		130	%
Total revenues	$	71,428	$	47,669	$	23,759	50	%
Realized prices
Oil ($/Bbl)	$	91.90	$	75.87	$	16.03	21	%
Natural gas ($/Mcf)	5.52		5.28		0.24		5	%
NGLs ($/Bbl)	40.90		38.92		1.98		5	%
Equivalents ($/Boe)	$	64.64	$	55.76	$	8.88	16	%
Operating expenses:
Gathering, transportation and marketing	$	2,003	$	1,851	$	152	8	%
Severance and ad valorem taxes	4,331		2,815		1,516		54	%
Depreciation, depletion, and amortization	12,313		9,548		2,765		29	%
General and administrative (before share-based compensation)	4,428		3,441		987		29	%
Total operating expenses (before share-based compensation)	$	23,075	$	17,655	$	5,420	31	%
General and administrative, share-based compensation	1,481		2,166		(685)		(32)	%
Total operating expenses	$	24,556	$	19,821	$	4,735	24	%
Other expenses:
Interest expense, net	$	914	$	596	$	318	53	%
Unit Expenses ($/Boe)
Gathering, transportation and marketing	$	1.85	$	2.19	$	(0.34)	(16)	%
Severance and ad valorem taxes	4.00		3.34		0.66		20	%
Depreciation, depletion and amortization	11.37		11.31		0.06		1	%
General and administrative (before share-based compensation)	4.09		4.08		0.01		—	%
General and administrative, share-based compensation	1.37		2.57		(1.20)		(47)	%
Interest expense, net	0.84		0.71		0.13		18	%

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Revenues

Total revenues for the three months ended March 31, 2022 increased 50%, or $23.8 million, compared to the three months ended December 31, 2021. The increase was attributable to a $23.0 million increase in mineral and royalty revenues and a $0.8 million increase in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 16% increase in realized commodity prices, resulting in an increase in royalty revenues of $9.6 million, and a 31% increase in production volumes to 12,031 Boe/d, resulting in an increase in royalty revenues of $13.4 million.

Oil revenues for the three months ended March 31, 2022 increased 55%, or $17.9 million, compared to the three months ended December 31, 2021. The increase in oil revenues was attributable to the 21% increase in realized oil prices to $91.90 per barrel, resulting in an increase in revenues of $8.8 million, and a 28% increase in oil production volumes to 6,128 barrels per day, resulting in a $9.1 million increase in oil revenues.

Natural gas revenues for the three months ended March 31, 2022 increased 35%, or $2.7 million, compared to the three months ended December 31, 2021. The increase in natural gas revenues was attributable to the 5% increase in realized natural gas prices to $5.52 per Mcf, resulting in an increase in revenues of $0.5 million, and a 29% increase in natural gas production volumes to 20,757 Mcf per day, resulting in a $2.2 million increase in natural gas revenues.

NGL revenues for the three months ended March 31, 2022 increased 35%, or $2.3 million, compared to the three months ended December 31, 2021. The increase in NGL revenues was attributable to the 5% increase in realized NGL prices to $40.90 per barrel, resulting in an increase in NGL revenues of $0.4 million, and a 29% increase in NGL production volumes to 2,444 Boe per day, resulting in a $1.9 million increase in NGL revenues.

Lease Bonus and Other Revenues

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The $0.8 million increase in revenues from lease bonus payments for the three months ended March 31, 2022 was primarily attributable to the $0.6 million and $0.2 million increases in leasing activity in the DJ and Permian Basins, respectively. Other revenues include payments for land easements (or "right-of-way") and surface damages and were not a significant portion of the overall amount.

Operating Expenses

Gathering, transportation and marketing expenses ("GTM"). For the three months ended March 31, 2022, GTM expenses increased 8% compared to the three months ended December 31, 2021, which is attributable to increased production volumes.

Severance and ad valorem taxes. For the three months ended March 31, 2022, severance and ad valorem taxes increased 54% compared to the three months ended December 31, 2021, primarily due to the increase in mineral and royalty revenues which was driven by increased realized commodity prices.

Depreciation, depletion and amortization. DD&A expense increased 29%, or $2.8 million, for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. This increase was due to higher production volumes, which increased our depletion expense by $2.7 million.

General and administrative and share-based compensation. General and administrative expense (before share-based compensation) increased 29%, or $1.0 million, for the three months ended March 31, 2022 compared to the three months ended December 31, 2021 as a result of increased compensation costs of $0.5 million, legal fees of $0.3 million and professional services of $0.2 million. The incremental compensation costs were primarily due to the implementation of a short-term incentive plan ("STIP") during 2022. The STIP awards reallocated a portion of the annual LTIP awards for executives and certain other employees in 2022 from share-based awards to performance-based bonuses. As such, the increase in compensation costs is offset by the decline in share-based compensation described below.

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Share-based compensation expense for the three months ended March 31, 2022 was $1.5 million, net of $0.6 million of share-based compensation cost capitalized to unevaluated property and $0.6 million of share-based compensation cost capitalized to evaluated property. Share-based compensation expense for the three months ended December 31, 2021 was $2.2 million, net of $0.6 million of share-based compensation cost capitalized to unevaluated property and $2.0 million of share-based compensation cost capitalized to evaluated property. The sequential decrease in share-based compensation expense of $0.7 million was primarily due to the reallocation of a portion of the annual LTIP awards for executives and certain other employees in 2022 from share-based awards to performance-based bonuses under the STIP, vesting of awards and the timing of the share-based awards granted during the three months ended March 31, 2022. See table below for additional details (in thousands).

	Three Months Ended
	March 31, 2022		December 31, 2021		Variance
Incentive units	$	178	$	178	$	—
RSAs	125		163		(38)
RSUs	1,426		2,526		(1,100)
PSUs	974		1,872		(898)
STIP awards	8		—		8
Capitalized share-based compensation	(1,230)		(2,573)		1,343
Total share-based compensation expense	$	1,481	$	2,166	$	(685)

Interest expense, net. Interest expense, net increased $0.3 million for the three months ended March 31, 2022 compared to the three months ended December 31, 2021, primarily due to the sequential increase of the weighted average debt outstanding on our revolving credit facility from $60.8 million to $93.0 million as shown in the table below (in thousands, except for interest rate).

	Three Months Ended
	March 31, 2022			December 31, 2021			Variance
Interest expense - revolving credit facility	$	692		$	409		$	283
Commitment fees	128			111			17
Amortization of loan closing costs	131			96			35
Interest income	(37)			(20)			(17)
Total interest expense, net	$	914		$	596		$	318
Total weighted average interest rate	2.96		%	2.65		%
Total weighted average debt balance	$	93,000		$	60,826

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

The following table provides the components of our revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes (dollars in thousands, except for realized prices and unit expenses):

	Three Months Ended March 31,
	2022		2021		Variance
Production:
Oil (MBbls)	552		411		141		34	%
Natural gas (MMcf)	1,868		1,451		417		29	%
NGLs (MBbls)	220		151		69		46	%
Equivalents (MBoe)	1,083		804		279		35	%
Equivalents per day (Boe/d)	12,031		8,931		3,100		35	%
Revenues:
Oil sales	$	50,688	$	22,813	$	27,875	122	%
Natural gas sales	10,312		5,437		4,875		90	%
NGL sales	8,995		3,926		5,069		129	%
Total mineral and royalty revenue	$	69,995	$	32,176	$	37,819	118	%
Lease bonus and other revenue	1,433		1,597		(164)		(10)	%
Total revenues	$	71,428	$	33,773	$	37,655	111	%
Realized prices
Oil ($/Bbl)	$	91.90	$	55.55	$	36.35	65	%
Natural gas ($/Mcf)	5.52		3.75		1.77		47	%
NGLs ($/Bbl)	40.90		25.97		14.93		57	%
Equivalents ($/Boe)	$	64.64	$	40.03	$	24.61	61	%
Operating expenses:
Gathering, transportation and marketing	$	2,003	$	1,733	$	270	16	%
Severance and ad valorem taxes	4,331		1,833		2,498		136	%
Depreciation, depletion, and amortization	12,313		9,367		2,946		31	%
General and administrative (before share-based compensation)	4,428		3,142		1,286		41	%
Total operating expenses (before share-based compensation)	$	23,075	$	16,075	$	7,000	44	%
General and administrative, share-based compensation	1,481		2,300		(819)		(36)	%
Total operating expenses	$	24,556	$	18,375	$	6,181	34	%
Other expenses:
Interest expense, net	$	914	$	267	$	647	242	%
Unit Expenses ($/Boe)
Gathering, transportation and marketing	$	1.85	$	2.16	$	(0.31)	(14)	%
Severance and ad valorem taxes	4.00		2.28		1.72		75	%
Depreciation, depletion and amortization	11.37		11.65		(0.28)		(2)	%
General and administrative (before share-based compensation)	4.09		3.91		0.18		5	%
General and administrative, share-based compensation	1.37		2.86		(1.49)		(52)	%
Interest expense, net	0.84		0.33		0.51		155	%

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Revenues

Total revenues for the three months ended March 31, 2022 increased 111%, or $37.7 million, compared to the three months ended March 31, 2021. The increase was attributable to a $37.8 million increase in mineral and royalty revenues partially offset by a $0.1 million decrease in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 61% increase in realized commodity prices, resulting in an increase in royalty revenues of $26.6 million, and a 35% increase in production volumes to 12,031 Boe/d, resulting in an increase in royalty revenues of $11.2 million.

Oil revenues for the three months ended March 31, 2022 increased 122%, or $27.9 million, compared to the three months ended March 31, 2021. The increase in oil revenues was attributable to the 65% increase in realized oil prices to $91.90 per barrel, resulting in an increase in revenues of $20.1 million, and a 34% increase in oil production volumes to 6,128 barrels per day, resulting in a $7.8 million increase in oil revenues.

Natural gas revenues for the three months ended March 31, 2022 increased 90%, or $4.9 million, compared to the three months ended March 31, 2021. The increase in natural gas revenues was attributable to the 47% increase in realized natural gas prices to $5.52 per Mcf, resulting in an increase in revenues of $3.3 million, and a 29% increase in natural gas production volumes to 20,757 Mcf per day, resulting in a $1.6 million increase in natural gas revenues.

NGL revenues for the three months ended March 31, 2022 increased 129%, or $5.1 million, compared to the three months ended March 31, 2021. The increase in NGL revenues was attributable to the 57% increase in realized NGL prices to $40.90 per barrel, resulting in an increase in NGL revenues of $3.3 million, and a 46% increase in NGL production volumes to 2,444 Boe per day, resulting in a $1.8 million increase in NGL revenues.

Lease Bonus and Other Revenues

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The $0.1 million decrease in revenues from lease bonus payments for the three months ended March 31, 2022 was primarily attributable to the $0.7 million decrease in leasing activity in the Permian Basin slightly offset by an increase in leasing activity in the DJ Basin of $0.6 million. Other revenues include payments for land easements (or "right-of-way") and surface damages and were not a significant portion of the overall amount.

Operating Expenses

Gathering, transportation and marketing expenses ("GTM"). For the three months ended March 31, 2022, GTM expenses increased 16% compared to the three months ended March 31, 2021, which is attributable to increased production volumes.

Severance and ad valorem taxes. For the three months ended March 31, 2022, severance and ad valorem taxes increased 136% compared to the three months ended March 31, 2021, primarily due to the increase in mineral and royalty revenues which was driven by increased realized commodity prices and production volumes.

Depreciation, depletion and amortization. DD&A expense increased 31%, or $2.9 million, for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021. This increase was due to higher production volumes, which increased our depletion expense by $3.2 million, partially offset by a lower depletion rate, which reduced our depletion expense by $0.3 million.

General and administrative and share-based compensation. General and administrative expense (before share-based compensation) increased 41%, or $1.3 million, for the three months ended March 31, 2022 compared to the three months ended March 31, 2021 as a result of increased compensation costs of $0.6 million, legal fees of $0.2 million and professional services of $0.4 million. The incremental compensation costs were primarily due to the implementation of the STIP during 2022. The STIP awards reallocated a portion of the annual LTIP awards for executives and certain other employees in 2022 from share-based awards to performance-based bonuses. As such, the increase in compensation costs is offset by the decline in share-based compensation described below.

33

Share-based compensation expense for the three months ended March 31, 2022 was $1.5 million, net of $0.6 million of share-based compensation cost capitalized to unevaluated property and $0.6 million of share-based compensation cost capitalized to evaluated property. Share-based compensation expense for the three months ended March 31, 2021 was $2.3 million, net of $0.9 million of share-based compensation cost capitalized to unevaluated property and $0.7 million of share-based compensation cost capitalized to evaluated property. The decrease in share-based compensation expense of $0.8 million was primarily due to the reallocation of a portion of the annual LTIP awards for executives and certain other employees in 2022 from share-based awards to performance-based bonuses under the STIP, vesting of awards and the timing of the share-based awards granted during the three months ended March 31, 2022. See table below for additional details (in thousands).

	Three Months Ended March 31,
	2022		2021		Variance
Incentive units	$	178	$	178	$	—
RSAs	125		134		(9)
RSUs	1,426		2,542		(1,116)
PSUs	974		1,079		(105)
STIP awards	8		—		8
Capitalized share-based compensation	(1,230)		(1,633)		403
Total share-based compensation expense	$	1,481	$	2,300	$	(819)

Interest expense, net. Interest expense, net increased $0.6 million for the three months ended March 31, 2022 compared to the three months ended March 31, 2021, primarily due to the increase of the weighted average debt outstanding on our revolving credit facility from $23.9 million to $93.0 million as shown in the table below (in thousands, except for interest rate).

	Three Months Ended March 31,
	2022			2021			Variance
Interest expense - revolving credit facility	$	692		$	113		$	579
Commitment fees	128			104			24
Amortization of loan closing costs	131			58			73
Interest income	(37)			(8)			(29)
Total interest expense, net	$	914		$	267		$	647
Total weighted average interest rate	2.96		%	1.83		%
Total weighted average debt balance	$	93,000		$	23,911

Factors Affecting the Comparability of Our Results of Operations

Our future results of operations may not be comparable to the historical results of operations for the periods presented, primarily for the reasons described below.

Corporate Transactions

The change in ownership interest in Brigham LLC from March 31, 2021 to March 31, 2022 impacts the attribution of net income between Brigham Minerals' stockholders and Brigham LLC Unit Holders.

As of March 31, 2021, Brigham Minerals owned a 77.0% interest in Brigham LLC and the Brigham LLC Unit Holders owned 23.0% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, collectively owned 16.9% of the outstanding voting stock of Brigham Minerals as of March 31, 2021.

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As of December 31, 2021, Brigham Minerals owned an 81.0% interest in Brigham LLC and the Brigham LLC Unit Holders owned 19.0% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, owned 4.8% and 8.7%, respectively, of the outstanding voting stock of Brigham Minerals as of December 31, 2021. Yorktown ceased to be an affiliate of the Company on January 20, 2022 in connection with the resignation of W. Howard Keenan, Jr. from the Board of Directors.

As of March 31, 2022, Brigham Minerals owned an 84.8% interest in Brigham LLC and the Brigham LLC Unit Holders owned 15.2% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, owned 5.0% of the outstanding voting stock of Brigham Minerals as of March 31, 2022.

Capital Requirements and Sources of Liquidity

Our current primary sources of liquidity are cash flows from operations, asset sales, borrowings under our revolving credit facility and proceeds from any primary issuances of equity securities. Future sources of liquidity may also include other credit facilities or increases to our current revolving credit facility we may enter into in the future and additional issuances of debt or equity securities. Even with the gradual easing of lockdown restrictions globally and the increase in commodities prices in 2021 and 2022, COVID-19 remains a global pandemic. As a result, our revenues and cash flows from operations may be negatively impacted and we may not have access to capital markets on terms favorable to us or at all.

Our primary uses of capital are for the payment of dividends to our stockholders, for investing in our business, specifically the acquisition of additional mineral and royalty interests, and for repaying amounts borrowed under our revolving credit facility. Our cash flows from operations may be negatively impacted by various factors discussed herein, and as a result, the dividend amount we are able to pay our stockholders may be negatively impacted.

As a mineral and royalty interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any development capital expenditures or lease operating expenses, which are entirely borne by the operator. As a result, the vast majority of our capital expenditures are related to our acquisition of additional mineral and royalty interests. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operations, investing and financing activities and our ability to assimilate acquisitions. For the three months ended March 31, 2022, we deployed approximately $45.0 million for acquisition-related capital expenditures, inclusive of $1.2 million capitalized share-based compensation expense and $20.4 million of equity. In addition to acquisitions, we have certain contractual long-term capital requirements associated with our office lease and with our revolving credit facility. See "Note 8 – Leases” and "Note 7 – Long-Term Debt” to the condensed consolidated financial statements of Brigham Minerals included elsewhere in this Quarterly Report. We periodically assess changes in current and projected free cash flows, acquisition and divestiture activities, debt requirements and other factors to determine the effects on our liquidity. Based upon our current oil, natural gas and NGL price expectations for the year ended December 31, 2022, we believe that our retained cash flow from operations, lease bonus, portfolio optimization activities and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through additional borrowings, joint venture partnerships, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.

Our liquidity as of March 31, 2022 is as follows (in thousands):

	March 31, 2022
Cash and cash equivalents	$	6,213
Revolving credit facility availability	$	137,000
Total liquidity	$	143,213

Associated with the Company's late-May semi-annual borrowing base redetermination under its revolving credit facility, the Administrative Agent has indicated a preliminary recommended borrowing base increase to $300.0 million. Pro-forma for the anticipated increase in the borrowing base, the Company would have had total liquidity of $213.2 million as of March 31, 2022.

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Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $42.0 million at March 31, 2022, as compared to $33.1 million at December 31, 2021. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.

When new wells are turned to sales, our collection of receivables has lagged approximately six months from initial production as operators complete the division order process, at which point we are paid in arrears and then kept current. Our cash and cash equivalents balance totaled $6.2 million and $20.8 million at March 31, 2022 and December 31, 2021, respectively. The decrease in cash and cash equivalents was primarily due to the payment of dividends to our stockholders and distributions to the holders of non-controlling interests, acquisitions of oil and gas properties and the payment of employee tax withholding obligations for the settlement of share-based compensation awards. These declines were partially offset by an increase in cash flow from operations and proceeds from the sale of mineral and royalty interests. See "Note 4—Acquisitions and Divestitures" to the condensed consolidated financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion. We expect that our cash flows from operations and additional borrowings under our revolving credit facility will be sufficient to fund our working capital needs. We expect that the pace of our operators’ drilling and completion of our undeveloped locations, production volumes, commodity prices and differentials to WTI and Henry Hub prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.

Dividends

The following table sets forth information with respect to cash dividends declared by our Board of Directors during the three months ended March 31, 2022:

Declaration Date	Record Date	Payment Date	Dividend Amount		Dividends paid (in thousands) (1)
February 18, 2022	March 18, 2022	March 25, 2022	$	0.45	$	23,979

(1) Dividends paid to holders of Class A common stock.

On May 1, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.60 per share of Class A common stock payable on May 27, 2022, to stockholders of record at the close of business on May 20, 2022. See "Note 15—Subsequent Events" to the condensed consolidated financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

Our current dividend structure consists of a base dividend of $0.16 per share of Class A common stock plus a variable dividend. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our results of operations, financial condition, capital requirements, contractual restrictions, credit agreement restrictions, restrictions imposed by applicable law and other factors that the Board of Directors deems relevant at the time of such determination.

Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):

	Three Months Ended March 31,
	2022		2021
Net cash provided by operating activities	$	42,143	$	22,089
Net cash used in investing activities	(17,593)		(21,936)
Net cash used in financing activities	(39,355)		(3,737)

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Analysis of Cash Flow Changes For the Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

Net cash provided by operating activities

Net cash provided by operating activities is primarily affected by production volumes, the prices of oil, natural gas, and NGLs, lease bonus and other revenues and changes in working capital. The increase in net cash provided by operating activities for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021 was primarily due to the 61% increase in realized commodity prices during the three months ended March 31, 2022 and the 35% increase in production volumes.

Net cash used in investing activities

Net cash used in investing activities is primarily comprised of acquisitions of mineral and royalty interests, net of dispositions. For the three months ended March 31, 2022, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $23.6 million, partially offset by sales of mineral and royalty interests totaling $7.1 million. For the three months ended March 31, 2021, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests of $21.9 million.

Net cash used in financing activities

Net cash used in financing activities for the three months ended March 31, 2022 was primarily due to the dividends paid to holders of our Class A common stock of $24.0 million, payment of employee tax withholding for settlement of equity compensation awards of $9.5 million and distributions to holders of non-controlling interest of $5.7 million. Net cash used in financing activities for the three months ended March 31, 2021 was primarily due to the dividends paid to holders of our Class A common stock of $11.3 million, distributions to holders of non-controlling interest of $3.4 million and payment of employee tax withholding for settlement of equity compensation awards of $1.0 million, partially offset by borrowings under our revolving credit facility of $12.0 million.

Revolving Credit Facility

On May 16, 2019, Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as administrative agent (the "Administrative Agent") for the various lenders from time to time party thereto, providing for a revolving credit facility (our “revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is collateralized by a lien on a substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including a substantial portion of their respective royalty and mineral properties.

Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination semi-annually. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. Brigham Resources can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The weighted average interest rate for the three months ended March 31, 2022 was 2.96%. As of March 31, 2022, the elected borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million, resulting in $137.0 million available for future borrowings.

Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our borrowing base. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions.

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Our revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the Administrative Agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Associated with the Company's late-May semi-annual borrowing base redetermination under its revolving credit facility, the Administrative Agent has indicated a preliminary recommended borrowing base increase to $300.0 million. Pro-forma for the anticipated increase in the borrowing base, the Company would have had total liquidity of $213.2 million as of March 31, 2022.

Off-Balance Sheet Arrangements

As of March 31, 2022, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

As of March 31, 2022, there have been no material changes to our critical accounting policies and related estimates previously disclosed in our Annual Report. See "Note 2—Summary of Significant Accounting Policies."

Item 3. — Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that our operators receive for the oil, natural gas and NGLs produced from our properties. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. During the past five years, the posted price for WTI has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022, and as of March 31, 2022, the posted price for oil was $100.53 per barrel. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise fluctuated and are likely to continue following that market. Prices for domestic natural gas have also fluctuated significantly over the last several years. During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021, and as of March 31, 2022, the Henry Hub spot market price of natural gas was $5.46 per MMBtu. The prices our operators receive for the oil, natural gas and NGLs produced from our properties depend on numerous factors beyond their and our control, some of which are previously disclosed under "Risk Factors" in our Annual Report.

A $1.00 per barrel change in our realized oil price would have resulted in a $0.6 million change in our oil revenues for the three months ended March 31, 2022. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the three months ended March 31, 2022. A $1.00 per barrel change in NGL prices would have resulted in a $0.2 million change in our NGL revenues for the three months ended March 31, 2022. Total revenues for the three months ended March 31, 2022 was comprised of 71% from oil sales, 14% from natural gas sales, and 13% from NGL sales.

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We may enter into derivative instruments, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows for our debt service requirements. However, these instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. Our revolving credit facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves of oil and natural gas, calculated separately, for up to 60 months in the future.

We have not had any oil or gas derivatives contracts in place since December 31, 2019.

Counterparty and Customer Credit Risk

When we enter into them, our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we evaluate the credit standing of such counterparties as we deem appropriate.

Our principal exposures to credit risk are through 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. For further discussion, please refer to "Risk Factors" in our Annual Report.

Interest Rate Risk

Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. In conjunction with the transition from LIBOR to SOFR a credit spread adjustment will be applied on top of the legacy LIBOR grid to calculate the new SOFR margin. If we convert to SOFR on June 30, 2023 the credit spread adjustment will be set at 0.644 bps for overnight SOFR contracts and 11.448 bps, 26.161 bps and 42.826 bps for SOFR contracts of 1 month, 3 month and 6 month tenors, respectively. If we convert to SOFR before June 30, 2023 the credit spread adjustments will be based on market pricing. We may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions. The weighted average interest rate for the three months ended March 31, 2022 was 2.96%. As of March 31, 2022, the borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million, resulting in $137.0 million available for future borrowings. A 1-percentage-point increase in our interest rate would have increased our interest expense by $0.2 million for the three months ended March 31, 2022.

Item 4. — Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our 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 March 31, 2022. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at March 31, 2022.

Changes in Internal Control over Financial Reporting.

There have been no changes in our internal control over financial reporting (identified in connection with the evaluation required by Rules 13a-15(d) and 15d-15(d) of the Exchange Act) that occurred during the first quarter of 2022 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

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

Item 1A. — Risk Factors

Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our Class A common stock are described under the caption “Risk Factors” in our Annual Report. There have been no material changes in our risk factors from those previously disclosed under “Risk Factors” in our Annual Report.

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Item 6. — Exhibits

The exhibits required to be filed by Item 6 are set forth in the Exhibit Index included below.

EXHIBIT INDEX

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Brigham Minerals, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019).
3.2	Amended and Restated Bylaws of Brigham Minerals, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019).
10.1	Indemnification Agreement (Gaidarov) (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on April 8, 2022).
31.1*	Certificate of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certificate of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certificate of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certificate of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101	The following financial information from this Quarterly Report on Form 10-Q of Brigham Minerals, Inc. for the quarter ended March 31, 2022 is formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

________________    

*    The exhibits marked with the asterisk symbol (*) are filed or furnished with this Quarterly Report on Form 10-Q.

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SIGNATURES

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

Date:	May 4, 2022	BRIGHAM MINERALS, INC.
		By:	/s/ Robert M. Roosa
			Robert M. Roosa
			Chief Executive Officer
		By:	/s/ Blake C. Williams
			Blake C. Williams
			Chief Financial Officer

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