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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, 2021

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 43,811,302 shares of Class A common stock and 12,910,663 shares of Class B common stock outstanding as of April 30, 2021.

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BRIGHAM MINERALS, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2021

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, 2021 and December 31, 2020			1
			Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2021 and 2020			2
			Condensed Consolidated Statements of Changes in Equity for the Three Months Ended March 31, 2021 and 2020			3
			Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2021 and 2020			4
			Notes to Condensed Consolidated Financial Statements			5
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			35
Item 4.			Controls and Procedures			36
PART II			OTHER INFORMATION
Item 1.			Legal Proceedings			37
Item 1A.			Risk Factors			37
Item 6.			Exhibits			38
			SIGNATURES			39

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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.

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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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2021 (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 expected 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, 2020 (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;

•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;

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

•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;

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•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.

    

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PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

						March 31,						December 31,
(In thousands, except share amounts)						2021						2020
						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents						$	5,560					$	9,144
Accounts receivable						21,540						17,632
Prepaid expenses and other						1,753						3,693
Total current assets						28,853						30,469
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property						333,742						325,091
Evaluated property						503,133						488,301
Less accumulated depreciation, depletion, and amortization						(198,854)						(189,546)
Total oil and gas properties, net						638,021						623,846
Other property and equipment						5,588						5,587
Less accumulated depreciation						(4,691)						(4,632)
Other property and equipment, net						897						955
Deferred tax asset						23,704						24,920
Other assets, net						714						771
Total assets						$	692,189					$	680,961
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities						$	6,950					$	7,905
Total current liabilities						6,950						7,905
Long-term bank debt						32,000						20,000
Other non-current liabilities						1,020						1,126
Temporary equity						—						146,280
Equity:
Preferred stock, $0.01 par value; 50,000,000 authorized; no shares issued and outstanding at March 31, 2021 and December 31, 2020						—						—
Class A common stock, $0.01 par value; 400,000,000 authorized, 44,102,188 shares issued and 43,665,558 outstanding at March 31, 2021; 400,000,000 authorized, 43,995,124 issued and 43,558,494 outstanding at December 31, 2020						441						440
Class B common stock, $0.01 par value; 150,000,000 authorized, 13,056,111 shares issued and outstanding at March 31, 2021; 150,000,000 authorized, 13,167,687 shares issued and outstanding at December 31, 2020						—						—
Additional paid-in capital						552,008						601,129
Accumulated deficit						(95,584)						(92,392)
Treasury stock, at cost; 436,630 shares at March 31, 2021 and December 31, 2020						(3,527)						(3,527)
Total equity attributable to Brigham Minerals, Inc.						453,338						505,650
Non-controlling interest						198,881						—
Total equity						$	652,219					$	505,650
Total liabilities and equity						$	692,189					$	680,961

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

						Three Months Ended March 31,
(In thousands, except per share data)						2021						2020
REVENUES
Mineral and royalty revenues						$	32,176					$	28,374
Lease bonus and other revenues						1,597						3,906
Total revenues						33,773						32,280
OPERATING EXPENSES
Gathering, transportation and marketing						1,733						1,779
Severance and ad valorem taxes						1,833						1,752
Depreciation, depletion, and amortization						9,367						12,826
General and administrative						5,442						5,510
Total operating expenses						18,375						21,867
INCOME FROM OPERATIONS						15,398						10,413
Interest expense, net						(267)						(32)
Other income, net						13						2
Income before income taxes						15,144						10,383
Income tax expense						3,073						1,582
NET INCOME						$	12,071					$	8,801
Less: net income attributable to non-controlling interest						(3,475)						(4,095)
Net income attributable to Brigham Minerals, Inc. shareholders						$	8,596					$	4,706
NET INCOME PER COMMON SHARE
Basic						$	0.20					$	0.14
Diluted						$	0.20					$	0.14
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic						43,515						33,979
Diluted						43,754						33,979

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

												Three Months Ended March 31, 2021
												Class A Common Stock												Class B Common Stock												Additional Paid-In Capital						Accumulated Deficit						Treasury Stock												Non-controlling Interest						Total Equity
(In thousands)												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
												Three Months Ended March 31, 2020
												Class A Common Stock												Class B Common Stock												Additional Paid-In Capital						Accumulated Deficit						Treasury Stock												Non-controlling Interest						Total Equity
(In thousands)									Shares						Amount						Shares						Amount																		Shares						Amount
Balance - December 31, 2019												34,041						$	340					22,847						$	—					$	323,578					$	(6,599)					—						$	—					$	—					$	317,319
Adjustment of temporary equity to carrying value												—						—						—						—						206,017						—						—						—						—						206,017
Shares surrendered for tax withholding on vested equity awards												(7)						—						—						—						—						—						—						—						—						—
Conversion of shares of Class B Common Stock to Class A Common Stock												140						2						(140)						—						1,524						—						—						—						—						1,526
Deferred tax asset arising from conversion of shares of Class B Common Stock to Class A Common Stock												—						—						—						—						204						—						—						—						—						204
Share-based compensation												—						—						—						—						3,402						—						—						—						—						3,402
Dividends declared												—						—						—						—						—						(13,541)						—						—						—						(13,541)
Net income												—						—						—						—						—						4,706						—						—						—						4,706
Balance - March 31, 2020												34,174						$	342					22,707						$	—					$	534,725					$	(15,434)					—						$	—					$	—					$	519,633

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

						Three Months Ended March 31,
(In thousands)						2021						2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income						$	12,071					$	8,801
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization						9,367						12,826
Share-based compensation expense						2,300						1,884
Amortization of debt issuance costs						58						98
Deferred income taxes						736						2,440
Bad debt expense						—						244
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable						(3,908)						5,298
Decrease (increase) in other current assets						1,941						(414)
Decrease in other deferred charges						—						2
Decrease in accounts payable and accrued liabilities						(484)						(3,720)
Increase (decrease) in other long-term liabilities						8						(309)
Net cash provided by operating activities						$	22,089					$	27,150
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties						(21,935)						(25,260)
Additions to other fixed assets						(1)						(187)
Proceeds from sale of oil and gas properties, net						—						1,565
Net cash used in investing activities						$	(21,936)					$	(23,882)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowing of long-term debt						12,000						—
Dividends paid						(11,336)						(12,969)
Distribution to holders of non-controlling interest						(3,409)						(10,145)
Debt issuance costs						(1)						(181)
Payment of employee tax withholding for settlement of equity compensation awards						(991)						—
Net cash used in financing activities						$	(3,737)					$	(23,295)
Decrease in cash and cash equivalents and restricted cash						(3,584)						(20,027)
Cash and cash equivalents and restricted cash, beginning of period						9,144						51,133
Cash and cash equivalents and restricted cash, end of period						$	5,560					$	31,106
Supplemental disclosure of noncash activity:
Accrued capital expenditures						$	61					$	220
Capitalized share-based compensation cost						$	1,633					$	1,518
Temporary equity cumulative adjustment to redemption value						$	54,294					$	(206,017)
Supplemental cash flow information:
Cash (payments) for loan commitment fees and interest						$	(213)					$	(252)
Tax refund received						$	1,024					$	—

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

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED AND 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 a 77% 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. Brigham Minerals completed its initial public offering (the “IPO”) in April 2019 and a follow-on offering in December 2019 (the "December 2019 Offering").

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 the Permian Basin 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 37 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 25, 2021 (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, 2021 are not necessarily indicative of the results to be expected for the entire fiscal year ending December 31, 2021. Brigham Minerals operates in one segment: oil and natural gas exploration and production.

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 temporary equity at December 31, 2020 and as non-controlling interest at March 31, 2021, which will reduce net income attributable to the holders of Brigham Minerals' Class A common stock. For more information, see "Note 9—Temporary equity and 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

independent petroleum engineering firm. Quarterly reserve estimates are internally generated by our in-house engineering staff. 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 and combined financial statements and notes for the year ended December 31, 2020, 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, 2021.

Non-Controlling Interest

As of March 31, 2021, the holders of Class B common stock no longer control a majority of the votes of the Company's board of directors (the "Board of Directors") through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon each holder of Brigham LLC Unit's (each a "Brigham LLC Unit Holder") exercise of its Redemption Right (as hereinafter defined). As such, as of March 31, 2021, Brigham Minerals accounts for Brigham LLC Unit Holders' 23% interest in Brigham LLC not owned by Brigham Minerals as non-controlling interest. For further discussion, see “Note 9—Temporary equity and Non-controlling interest.”

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. We did not record a reserve for bad debt for the three months ended March 31, 2021. We recorded a reserve for bad debt of $0.2 million for the three months ended March 31, 2020 which was included in general and administrative expenses.

As of March 31, 2021 and December 31, 2020, accounts receivable was comprised of the following:

(In thousands)						March 31, 2021						December 31, 2020
Accounts receivable
Oil and gas sales						$	22,341					$	17,413
Reserve for bad debt						(855)						(855)
Other						54						1,074
Total accounts receivable						$	21,540					$	17,632

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
Customer (Operator) Name						March 31, 2021						March 31, 2020
Exxon Mobil Corp						16		%				8		%
Occidental Petroleum Corp						12		%				13		%
Continental Resources Inc.						10		%				9		%
Royal Dutch Shell PLC						9		%				16		%

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2021 and 2020, we received revenues from over 130 and 150 operators, respectively, with approximately 69% and 63% of revenues, respectively, coming from the top ten operators on our properties.

Recently Issued Accounting Standards Not Yet Adopted

Brigham Minerals’ status as an emerging growth company ("EGC") under Section 107 of the Jumpstart Our Business Startups Act of 2012 permits it to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. Brigham Minerals is choosing to take advantage of this extended transition period and, as a result, Brigham Minerals will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. If Brigham Minerals loses its status as an EGC before the adoption dates for private companies, Brigham Minerals will be required to accelerate the adoption of new or revised accounting standards.

In February 2016, the Financial Accounting Standards Board (the "FASB") issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented in the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The new standard becomes effective for us during the fiscal year ending December 31, 2022 and interim periods within the fiscal year ending December 31, 2023 yet early adoption is permitted. We are currently evaluating the impact that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU 2016-13 was subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. ASU 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the impact that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

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 $2.7 million and $2.4 million for the three months ended March 31, 2021 and 2020, 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 as of the dates shown consisted of the following:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(In thousands)						March 31, 2021						December 31, 2020
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property						$	333,742					$	325,091
Evaluated property						503,133						488,301
Total oil and gas properties, at cost						836,875						813,392
Less accumulated depreciation, depletion, and amortization						(198,854)						(189,546)
Total oil and gas properties, net						$	638,021					$	623,846

Capitalized costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $9.3 million and $12.2 million for the three months ended March 31, 2021 and 2020, respectively. Average depletion of proved properties was $11.58 per Boe and $12.94 per Boe for the three months ended March 31, 2021 and 2020, 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. As of March 31, 2021 and March 31, 2020, the SEC oil price and SEC gas price used in the calculation of the ceiling test were $40.01 and $55.71, respectively, per barrel of oil, and $2.18 and $2.32, respectively, per MMBtu of natural gas. There were no impairment charges during the three months ended March 31, 2021 and 2020.

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, such as occurred in the third and fourth quarters of 2020. 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

During the three months ended March 31, 2021 and 2020, 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. 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, 2021 were funded with our retained operating cash flow and lease bonus and our revolving credit facility (as hereinafter defined). The changes in the oil and natural gas property balance for the three months ended March 31, 2020 were funded with proceeds from the December 2019 Offering.

						Oil and Gas Properties Acquired												Cash Consideration Paid
(In thousands)						Evaluated						Unevaluated
Quarter Ended March 31, 2021						$	9,073					$	12,776					$	21,849

						Oil and Gas Properties Acquired												Cash Consideration Paid
(In thousands)						Evaluated						Unevaluated
Quarter Ended March 31, 2020						$	9,471					$	15,947					$	25,418

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Revenue From Contracts With Customers

Contract Balances

Oil, natural gas and NGL sales revenues are 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. Lease bonus and other revenues are recognized when the lease agreement has been executed, payment has been received, and the Company has no further obligation to refund the payment. 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. As of March 31, 2021, accounts receivable from oil and gas sales of $22.3 million represent rights to payment for which Brigham Minerals has satisfied its obligations under contracts with customers.

Prior-period performance obligations

Given we do not operate our properties, Brigham Minerals has limited visibility into the timing of when new wells start producing and 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 amount of production delivered to the purchaser is estimated on the basis of state-reported production data or production statements from operators. 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, 2021 and 2020, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

Allocation of transaction price to remaining performance obligations

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

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, 2021 and December 31, 2020.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2021 and March 31, 2020.

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 a 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, a wholly-owned subsidiary of Brigham LLC ("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 May and November of each year. 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, 2021 was 1.83%. As of March 31, 2021, the elected borrowing base on our revolving credit facility was $135.0 million, with outstanding borrowings of $32.0 million, resulting in $103.0 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, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans, 1.750% to 2.750%. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 only to no default or borrowing base deficiency) 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 4.00 to 1.00. As of March 31, 2021, we were in compliance with all covenants in accordance with our revolving credit facility.

8. Equity

Class A Common Stock

Brigham Minerals had approximately 43.7 million shares of its Class A common stock outstanding as of March 31, 2021. Holders of Class A common stock are entitled to one vote per share on all matters to be voted upon by the shareholders 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 shareholders after payment of liabilities.

Class B Common Stock

Brigham Minerals had approximately 13.1 million shares of its Class B common stock outstanding as of March 31, 2021. Holders of the Class B common stock are entitled to one vote per share on all matters to be voted upon by the shareholders. 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’ shareholders 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, 2021, 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 10—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, 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. For the three months ended March 31, 2020, the Incentive Units, RSUs, RSAs, and shares of Class B common stock were not recognized in dilutive EPS calculations as the effect 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 performance goals. 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.

The following table reflects the allocation of net income to common shareholders and EPS computations for the period indicated based on a weighted average number of common stock outstanding for the period:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

						Three Months Ended March 31,
(In thousands, except per share data)						2021						2020
Basic EPS
Numerator:
Basic net income attributable to Brigham Minerals, Inc. shareholders						$	8,596					$	4,706
Denominator:
Basic weighted average shares outstanding						43,515						33,979
Basic EPS attributable to Brigham Minerals, Inc. shareholders						$	0.20					$	0.14
Diluted EPS
Numerator:
Basic net income attributable to Brigham Minerals, Inc. shareholders						$	8,596					$	4,706
Diluted net income attributable to Brigham Minerals, Inc. shareholders						$	8,596					$	4,706
Denominator:
Basic weighted average shares outstanding						43,515						33,979
Effects of dilutive securities:
Unvested RSUs						230						—
Unvested RSAs						9						—
Diluted weighted average shares outstanding						43,754						33,979
Diluted EPS attributable to Brigham Minerals, Inc. shareholders						$	0.20					$	0.14

9. Temporary equity and Non-controlling interest

Temporary equity

Temporary equity represented the 23.2% interest in the units of Brigham LLC not owned by Brigham Minerals, as of December 31, 2020. Class B common stock was classified as temporary equity in the condensed consolidated balance sheet as of December 31, 2020, as pursuant to the Amended and Restated Limited Liability Company Agreement of Brigham LLC (the "Brigham LLC Agreement"), the Redemption Rights of a Brigham LLC Unit Holder for either shares of Class A common stock or an equivalent amount of cash was not solely within Brigham Minerals' control. This was due to the fact that the holders of Class B common stock controlled a majority of the votes of the Board of Directors through direct representation on the Board of Directors, which allowed the holders of Class B common stock to control the determination of whether to make a cash payment upon a Brigham LLC Unit Holder's exercise of its Redemption Right.

As a result of the appointment of an additional independent member to our Board of Directors on February 19, 2021, the holders of Class B common stock no longer hold a majority of the votes of the Board of Directors and no longer control the Board of Directors through direct representation on the Board of Directors. Consequently, after February 19, 2021, Class B common stock is presented as non-controlling interest (as discussed below) in the condensed consolidated balance sheet of Brigham Minerals.

Temporary equity was recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital. For the period from January 1, 2021 to February 18, 2021, Brigham Minerals recorded adjustments to the value of temporary equity as presented in the table below:

(In thousands)						Temporary Equity Adjustments
Balance - December 31, 2020 (1)						$	146,280
Net income attributable to temporary equity						1,922
Adjustment of temporary equity to redemption value						54,294
Reclassification to non-controlling interest (2)						$	(202,496)
Balance - February 18, 2021						$	—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)Based on 13,167,687 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $11.11 at December 31, 2020.

(2)Based on 13,167,687 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $15.38 at February 18, 2021. The February 18, 2021 redemption value of temporary equity became the carrying value of non-controlling interest, as discussed below.

Non-controlling Interest

Non-controlling interest represents the 23.0% interest in the units of Brigham LLC not owned by Brigham Minerals, as of March 31, 2021. Class B common stock is classified as non-controlling interest in the condensed consolidated balance sheet as of March 31, 2021.

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 shareholders generally, and holders of Brigham LLC Units (and Class B common stock) have a redemption right into shares of Class A common stock. As discussed below, following the IPO:

•Each Brigham LLC Unit Holder other than Brigham Minerals and its subsidiaries, received a number of shares of Class B common stock equal to the number of Brigham LLC Units held by such Brigham LLC Unit Holder following the IPO;

•Brigham Minerals contributed, directly or indirectly, the net proceeds of the IPO to Brigham LLC in exchange for an additional number of Brigham LLC Units such that Brigham Minerals held, directly or indirectly, a total number of Brigham LLC Units equal to the number of shares of Class A common stock outstanding following the IPO; and

•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.

Non-controlling interest is recorded at its carrying value. For the period from February 19, 2021 to March 31, 2021, the Company recorded adjustments to the value of non-controlling interest as presented in the table below:

(In thousands)						Non-controlling interest
Balance - February 19, 2021						$	—
Reclassification from temporary equity (1)						202,496
Conversion of Class B common stock to Class A common stock						(1,721)
Net income attributable to non-controlling interest (2)						1,553
Distribution to holders of non-controlling interest						(3,447)
Balance - March 31, 2021						$	198,881

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)Represents the February 19, 2021, redemption value of temporary equity, prior to its reclassification to non-controlling interest. Based on 13,167,687 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $15.38 at February 18, 2021.

(2)Net income attributable to non-controlling interest includes the period from February 19, 2021 through March 31, 2021.

10. 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, 2021, 3,028,367 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. The RSAs generally vested in one-third increments on each of April 23, 2020 and 2021 and will vest as to the final one-third increment on April 23, 2022 and 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 lapse of such restrictions.

The following table summarizes activity related to RSAs for the three months ended March 31, 2021.

						Restricted Stock Awards
						Number of RSAs						Grant Date Fair Value
Unvested at January 1, 2021						68,293						$	21.25
Vested						—						$	—
Forfeited						(4,512)						$	21.25
Unvested at March 31, 2021						63,781						$	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 generally vest in one-third increments over a three-year period and 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. During the three months ended March 31, 2021, the Company granted 527,778 RSUs. The share-based compensation expense of such RSUs was determined using the closing price of Class A common stock on February 24, 2021, the date of grant, of $16.11.

The following table summarizes activity related to RSUs for the three months ended March 31, 2021.

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

						Restricted Stock Units
						Number of RSUs						Weighted-Average Grant Date Fair Value
Unvested at January 1, 2021						562,871						$	17.81
Granted						527,778						$	16.11
Vested						—						$	—
Forfeited						(2,710)						$	18.29
Unvested at March 31, 2021						1,087,939						$	16.98

The Company has granted PSUs to certain officers and managers, which vest based on continuous employment and satisfaction of a performance metric based on the absolute total shareholder 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. 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, 2021. In addition, no PSUs became vested or were forfeited during the three months ended March 31, 2021:

						Performance-Based Restricted Stock Units
						Target PSUs												Grant Date Fair Value
Unvested at January 1, 2021						1,187,811												$	10.07
Granted (1)						—												—
Unvested at March 31, 2021						1,187,811												$	10.07

(1)In February 2021, the Compensation Committee of the Board of Directors approved a grant of 472,377 PSUs and management is in the process of executing the award agreements. However, as all terms of the grant have not yet been agreed to, a grant date has not been established as of March 31, 2021.

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, 2021 and 2020 is summarized in the table below.

						Three Months Ended March 31,
(In thousands)						2021						2020
Incentive Units (1)						$	178					$	178
RSAs (1) (4)						134						700
RSUs (1)						2,542						1,594
PSUs (2)						1,079						930
Capitalized share-based compensation (3)						(1,633)						(1,518)
Total share-based compensation expense						$	2,300					$	1,884

(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)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 of share-based compensation cost to evaluated property.

(4)During the three months ended March 31, 2020, share-based compensation cost included $0.5 million associated with the accelerated vesting of 30,174 RSAs for certain employees who retired in February 2020.

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2021, a portion of which will be capitalized:

						Incentive Units						RSAs						RSUs						PSUs						Total
Year						(In thousands)
2021						$	534					$	511					$	7,110					$	3,296					$	11,451
2022						534						209						5,477						966						7,186
2023						—						—						2,828						—						2,828
Total						$	1,068					$	720					$	15,415					$	4,262					$	21,465

11. 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:

						Three Months Ended March 31,
(In thousands, except for tax rate)						2021						2020
Income tax expense						$	3,073					$	1,582
Effective tax rate						20.3		%				15.2		%

Total income tax expense for the three months ended March 31, 2021 and 2020 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of 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, 2021 and 2020 reflects Brigham Minerals’ ownership interest in Brigham LLC of 77% and 60.1%, respectively, at the end of each period.

12. Commitments and Contingencies

Commitments

Brigham Minerals leases office space under operating leases. Rent expense for the three months ended March 31, 2021 and 2020 was $0.3 million and $0.2 million, respectively. Future minimum lease commitments under non-cancelable operating leases at March 31, 2021 are presented below:

(In thousands)						Commitment
Year
2021 (remainder of)						$	956
2022						1,310
2023						1,347
2024						1,384
2025						1,419
Thereafter						2,251
Total						$	8,667

Contingencies

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2021 and December 31, 2020.

13. COVID-19 Pandemic and Winter Storm Uri

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, has caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. The declining commodity prices adversely affected the revenues the Company receives for its royalty interests and could affect its ability to access the capital markets on terms favorable to the Company. Additionally, in response to the decline in commodity prices, many operators on the Company's properties have announced reductions in their estimated capital expenditures for 2021 and beyond, which has and will adversely affect the near-term development of the Company's properties in 2021 and beyond. While these lower commodity prices initially resulted in some of the Company's operators shutting in or curtailing production from wells on its properties during the second quarter of 2020, the Company saw a majority of its operators resume production for previously curtailed and shut in wells in connection with the improvement of commodity prices in the second half of 2020 and the first quarter of 2021.

The Company is currently operating its office at 100% capacity while continuing to support remote working for its employees that are considered high-risk pursuant to the Center for Disease Control and Prevention guidelines or have household members meeting the criteria of those guidelines. The Company has not experienced material disruptions to its operations or the health of its workforce and has maintained the engagement and connectivity of its personnel.

Winter Storm Uri

In February 2021, Winter Storm Uri caused severe winter weather and freezing temperatures in the southern United States, which effected our properties in the Permian and Anadarko Basins, resulting in the curtailment of a portion of our production, delays in drilling and completion of wells, other operational constraints and ultimately adversely impacted our first quarter 2021 production. These curtailments, delay and operational constraints also resulted in increases in commodity prices, primarily natural gas prices. For example, the Henry Hub spot market price for natural gas for the month of February 2021 ranged from a low of $2.66 per MMBtu to a high of $23.86 per MMBtu. Given we do not operate our properties, Brigham Minerals has limited visibility into the timing of when production resumed and was required to estimate the amount of production delivered to the purchaser and the price that will be ultimately received for the sale of the product.

14. Subsequent Events

On May 4, 2021, the Board of Directors of Brigham Minerals declared a dividend of $0.32 per share of Class A common stock payable on May 28, 2021, to shareholders of record at the close of business on May 21, 2021.

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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 indirectly 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 and combined financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2020 (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 spread of the COVID-19 pandemic, 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 shareholders through (i) the organic 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, 2021, we owned 87,930 net royalty acres across 37 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 8,931 Boe/d (70% liquids, 51% oil) for the three months ended March 31, 2021 decreased 5% compared to the three months ended December 31, 2020 and decreased 14% compared to the three months ended March 31, 2020. The recent Winter Storm Uri in February 2021 adversely affected operator activity and production volumes in the southern United States, including in the Permian and Anadarko Basins. This resulted in production curtailment which accounted for the total decrease in production volumes relative to fourth quarter 2020. The decrease in production volumes relative to first quarter 2020 was primarily due to the reduction in drilling activity during the second half of 2020.

•Our royalty revenues comprised of crude oil, natural gas and NGL sales for the three months ended March 31, 2021 increased 35% to $32.2 million compared to the three months ended December 31, 2020 due to a 45% increase in realized commodity pricing and increased 13% compared to the three months ended March 31, 2020 due to a 34% increase in realized commodity pricing, despite the decrease in production volumes.

•Our net income for the three months ended March 31, 2021 was $12.1 million compared to a net loss of $47.0 million for the three months ended December 31, 2020 and net income of $8.8 million for the three months ended March 31, 2020.

•Adjusted Net Income for the three months ended March 31, 2021 was $12.1 million and increased 347% as compared to the three months ended December 31, 2020 and increased 37% as compared to the three months ended March 31, 2020. Adjusted Net Income is a non-GAAP financial measure. For a definition of Adjusted Net Income 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."

•Adjusted EBITDA and Adjusted EBITDA ex lease bonus for the three months ended March 31, 2021 were $27.1 million, and $25.5 million, respectively, and increased 57% and 48%, respectively, as compared to the three months ended December 31, 2020 and increased 8%, and 20%, respectively, as compared to the three months ended March 31, 2020. 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

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calculated and presented in accordance with GAAP, please read "How We Evaluate our Operations—Non-GAAP Financial Measures."

•On May 4, 2021, the Board of Directors of Brigham Minerals declared a dividend of $0.32 per share of Class A common stock payable on May 28, 2021 to shareholders of record at the close of business on May 21, 2021.

•As of March 31, 2021, Brigham Minerals had a cash balance of $5.6 million and $103.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of $108.6 million. 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 $165 million. In addition to the increase in the borrowing base, there are several proposed changes to the terms of the revolving credit facility, including various affirmative, negative, and financial maintenance covenants.

Market Environment and COVID-19

The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in demand for crude oil and the price for oil in 2020. Additionally, in March 2020, Saudi Arabia and Russia failed to agree to and maintain oil price and production controls within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. While OPEC, Russia, and other oil and gas producing countries ("OPEC+") subsequently agreed to collectively decrease production, these events, combined with the macro-economic impact of the continued outbreak of the COVID-19 pandemic and declining availability of hydrocarbon storage, exacerbated the decline in commodity prices, including the historic, record low price of negative $36.98 per barrel that occurred in April 2020. Since then, OPEC+ and Saudi Arabia have agreed to continued production decreases; however, OPEC+ and Saudi Arabia are currently planning to begin easing production cuts starting in May 2021. Market volatility has continued, and we expect it will continue for the foreseeable future. Please see “Risk Factors” in our Annual Report for further discussion of these events.

In response to the decline of commodity prices during 2020 and the current supply and demand imbalances, many operators on our properties have announced reductions in their estimated capital expenditures for 2021 and beyond, which has and will adversely affect the near-term development of the Company's properties in 2021 and beyond. We cannot predict the extent and duration of these and other impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.

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 the first quarter of 2021, along with our financial strength, we believe we are well positioned to capture attractive opportunities for the remainder of 2021 that will generate shareholder value. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations and borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy.

The company is currently operating its office at 100% capacity while continuing to support working from home for our employees that are considered high-risk pursuant to the Centers for Disease Control and Prevention guidelines or have household members meeting the criteria of the guidelines. The Company has not experienced material disruptions to our operations or the health of our workforce.

Winter Storm Uri

In February 2021, Winter Storm Uri caused severe winter weather and freezing temperatures in the southern United States, which effected our properties in the Permian and Anadarko Basins, resulting in the curtailment of a portion of our production, delays in drilling and completion of wells, other operational constraints and ultimately adversely impacted our first quarter 2021 production. These curtailments, delays and operational constraints also resulted in increases in commodity prices, primarily natural gas prices. For example, the Henry Hub spot market price for natural gas for the month of February 2021 ranged from a low of $2.66 per MMBtu to a high of $23.86 per MMBtu. Given we do not operate our properties, Brigham Minerals has limited visibility into the timing of when production resumed and was required to estimate the amount of production delivered to the purchaser and the price that will be ultimately received for the sale of the product.

Operational Update

Mineral and Royalty Interest Ownership Update

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During the first quarter 2021, the Company completed 15 transactions, acquiring 1,645 net royalty acres (standardized to a 1/8th royalty interest) and deploying $21.8 million in capital primarily in the Permian Basin. As of March 31, 2021, the Company owned roughly 87,930 net royalty acres, encompassing 13,450 gross (115.6 net) undeveloped horizontal locations, across 37 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 table below summarizes the Company’s mineral and royalty interest ownership at the dates indicated.

						Delaware						Midland						SCOOP						STACK						DJ						Williston						Other						Total
Net Royalty Acres
March 31, 2021						28,940						5,775						11,400						10,725						16,320						7,980						6,790						87,930
December 31, 2020						28,330						5,220						11,400						10,725						15,890						7,950						6,770						86,285
Acres Added Q/Q						610						555						—						—						430						30						20						1,645
% Added Q/Q						2%						11%						—%						—%						3%						—%						—%						2%

Operating Activity Update

DUC Conversions

The Company identified approximately 97 gross (0.4 net) DUCs converted to production during the first quarter 2021, which represented 13% of its gross DUCs (11% of net) in inventory as of year-end 2020. First quarter 2021 DUC and PDP conversion waterfalls are summarized in the charts below:

Drilling Activity

During the first quarter 2021, the Company identified 132 gross (1.0 net) wells spud on its mineral position, which represents a 150% increase in net well drilling activity relative to fourth quarter 2020. Brigham’s gross and net wells spud activity per quarter is summarized in the chart below:

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DUC and Permit Inventory

The net DUC and permit inventories increased quarter over quarter. Brigham Minerals ended the first quarter 2021 with 4.4 net DUCs and 4.7 net permits up from 3.6 net DUCs and 4.2 net permits as of year-end 2020, representing a 20% and 12% sequential increase respectively. The sequential inventory increase was largely driven by an increase in net Permian DUCs and permits. Brigham Minerals ended the first quarter 2021 with 2.7 net Permian DUCs and 2.5 net Permian permits up from 2.4 net Permian DUCs and 1.3 net Permian permits as of year-end 2020, representing a 10% and 96% sequential increase, respectively. Brigham Minerals' DUC and permit inventory as of March 31, 2021 by basin is outlined in the table below:

						Development Inventory by Basin (1)
						Delaware						Midland						SCOOP						STACK						DJ						Williston						Other						Total
Gross Inventory
DUCs						183						232						64						7						127						149						16						778
Permits						150						121						8						2						179						265						8						733
Net Inventory
DUCs						1.9						0.8						0.3						—						1.1						0.2						0.1						4.4
Permits						1.1						1.4						—						—						1.5						0.6						0.1						4.7

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

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.

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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.

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 $77.41 per barrel in June 2018. 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, 2021, the posted price for oil was $59.19 per barrel and the Henry Hub spot market price of natural gas was $2.52 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.

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, the effects of health epidemics 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

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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, 2021 and March 31, 2020, the SEC oil price and SEC gas price used in the calculation of the ceiling test were $40.01 and $55.71, respectively, per barrel for oil, and $2.18 and $2.32, respectively, per MMBtu for natural gas. There were no impairment charges during the three months ended March 31, 2021 and 2020.

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, such as occurred in the third and fourth quarters of 2020. 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 up to 60 months in the future. We had no natural gas or oil derivative contracts in place as of March 31, 2021 and December 31, 2020.

Non-GAAP Financial Measures

Adjusted Net Income, 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 Net Income as Net Income (Loss) before impairment of oil and gas properties, after tax. We define Adjusted EBITDA as Adjusted 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 Net Income, 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 Net Income, 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 Net Income, 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 Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to the most directly comparable GAAP financial measure for the periods indicated.

						Three Months Ended
(In thousands)						March 31, 2021						December 31, 2020						March 31, 2020
Reconciliation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to net income:
Net Income (Loss)						$	12,071					$	(46,962)					$	8,801
Add:
Impairment of oil and gas properties, after tax (1)						—						49,664						—
Adjusted Net Income						12,071						2,702						8,801
Add:
Depreciation, depletion, and amortization						9,367						12,411						12,826
Share-based compensation expense						2,300						1,836						1,884
Interest expense						267						195						32
Income tax expense						3,073						488						1,582
Less:
Other income, net						13						399						2
Adjusted EBITDA						$	27,065					$	17,233					$	25,123
Less:
Lease bonus and other revenues						1,597						—						3,906
Adjusted EBITDA ex lease bonus						$	25,468					$	17,233					$	21,217

(1) Tax effect of $11.0 million tax benefit for the three months ended December 31, 2020.

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,
						2021						2020
Royalty revenues
Oil sales						68		%				73		%
Natural gas sales						15		%				9		%
NGL sales						12		%				6		%
Total royalty revenue						95		%				88		%
Lease bonus and other revenues						5		%				12		%
Total revenues						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 shareholders, 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 1.00% 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

On November 19, 2020, the SEC adopted amendments to modernize and simplify Regulation S-K, including its Management’s Discussion and Analysis and certain financial disclosure requirements. Specifically, the final rule gives registrants the option to disclose their results of operations of the most recently completed fiscal quarter compared to the immediately preceding fiscal quarter rather than compared to the corresponding fiscal quarter of the prior year. We believe that a comparison of the results of operations of the most recently completed fiscal quarter to the immediately preceding fiscal quarter is more meaningful and useful to investors than comparing the most recently completed fiscal quarter to the corresponding fiscal quarter of the prior year, and we are voluntary complying with the amendments in this Quarterly Report. As a result of our voluntary compliance, we are presenting a comparison of the results of operations of the quarter ended March 31, 2021 to the quarter ended March 31, 2020 and also to the quarter ended December 31, 2020.

Three Months Ended March 31, 2021 Compared to Three Months Ended December 31, 2020

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:

						Three Months Ended
(Dollars in thousands, except for realized prices and unit expenses)						March 31, 2021						December 31, 2020						Variance
Production:
Oil (MBbls)						411						445						(34)						(8)		%
Natural gas (MMcf)						1,451						1,451						—						—		%
NGLs (MBbls)						151						175						(24)						(14)		%
Equivalents (MBoe)						804						861						(57)						(7)		%
Equivalents per day (Boe/d)						8,931						9,361						(430)						(5)		%
Revenues:
Oil sales						$	22,813					$	17,969					$	4,844					27		%
Natural gas sales						5,437						3,327						2,110						63		%
NGL sales						3,926						2,464						1,462						59		%
Total mineral and royalty revenue						$	32,176					$	23,760					$	8,416					35		%
Lease bonus and other revenue						1,597						—						1,597						100		%
Total revenues						$	33,773					$	23,760					$	10,013					42		%
Realized prices
Oil ($/Bbl)						$	55.55					$	40.40					$	15.15					38		%
Natural gas ($/Mcf)						3.75						2.29						1.46						64		%
NGLs ($/Bbl)						25.97						14.11						11.86						84		%
Equivalents ($/Boe)						$	40.03					$	27.59					$	12.44					45		%
Operating expenses:
Gathering, transportation and marketing						$	1,733					$	1,879					$	(146)					(8)		%
Severance and ad valorem taxes						1,833						1,427						406						28		%
Depreciation, depletion, and amortization						9,367						12,411						(3,044)						(25)		%
Impairment of oil and gas properties						—						60,664						(60,664)						(100)		%
General and administrative (before share-based compensation)						3,142						3,220						(78)						(2)		%
Total operating expenses (before share-based compensation)						$	16,075					$	79,601					$	(63,526)					(80)		%
Share-based compensation						2,300						1,837						463						25		%
Total operating expenses						$	18,375					$	81,438					$	(63,063)					(77)		%
Other expenses:
Interest expense, net						$	267					$	195					$	72					37		%
Total other expenses						$	267					$	195					$	72					37		%

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						Three Months Ended
Unit Expenses ($/Boe)						March 31, 2021						December 31, 2020						Variance
Gathering, transportation and marketing						$	2.16					$	2.18					$	(0.02)					(1)		%
Severance and ad valorem taxes						2.28						1.66						0.62						37		%
Depreciation, depletion and amortization						11.65						14.41						(2.76)						(19)		%
General and administrative (before share-based compensation)						3.91						3.74						0.17						5		%
General and administrative, share-based compensation						2.86						2.13						0.73						34		%
Interest expense, net						0.33						0.23						0.10						43		%

Revenues

Total revenues for the three months ended March 31, 2021 increased 42%, or $10.0 million, compared to the three months ended December 31, 2020. The increase was attributable to an $8.4 million increase in mineral and royalty revenues and a $1.6 million increase in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 45% increase in realized commodity prices, resulting in an increase in royalty revenues of $10.0 million. This was partially offset by a 5% decrease in production volumes to 8,931 Boe/d, resulting in a decrease in royalty revenues of $1.6 million. Operator production curtailments in Texas and Oklahoma resulting from the February 2021 Winter Storm Uri decreased production volumes in the first quarter 2021.

Oil revenues for the three months ended March 31, 2021 increased 27%, or $4.8 million, compared to the three months ended December 31, 2020. The increase in oil revenues was primarily attributable to the 38% increase in realized oil prices to $55.55 per barrel, resulting in an increase in revenues of $6.2 million. This was partially offset by an 8% decrease in oil production volumes to 4,563 barrels per day, resulting in a $1.4 million decrease in oil revenues.

Natural gas revenues for the three months ended March 31, 2021 increased 63%, or $2.1 million, compared to the three months ended December 31, 2020. The increase in natural gas revenues was attributable to the 64% increase in realized natural gas prices to $3.75 per Mcf, resulting in an increase in revenues of $2.1 million.

NGL revenues for the three months ended March 31, 2021 increased 59%, or $1.5 million, compared to the three months ended December 31, 2020. The increase in NGL revenues was primarily attributable to the 84% increase in realized NGL prices to $25.97 per barrel, resulting in an increase in NGL revenues of $1.8 million. This was partially offset by a 14% decrease in NGL volumes to 1,680 barrels per day, resulting in a decrease in revenues of $0.3 million.

Lease Bonus and Other Revenues

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The increase in revenues from lease bonus payments for the three months ended March 31, 2021 is primarily attributable to the increase in leasing activity in the Permian Basin. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Operating Expenses

Gathering, transportation and marketing expenses. For the three months ended March 31, 2021, GTM expenses decreased 8% compared to the three months ended December 31, 2020, primarily due to an overall 5% decrease in production volumes.

Severance and ad valorem taxes. For the three months ended March 31, 2021, severance and ad valorem taxes increased 28%, or $0.4 million, over the three months ended December 31, 2020, primarily due to the increase in mineral and royalty revenues which was driven by an increase in realized commodity prices of 45%.

Depreciation, depletion and amortization. DD&A expense decreased 25%, or $3.0 million, for the three months ended March 31, 2021 as compared to the three months ended December 31, 2020. A lower depletion rate decreased our depletion expense by $2.2 million and lower production volumes decreased our depletion expense by $0.8 million. The depletion rate was $11.58 per Boe and $14.34 per Boe for the three months ended March 31, 2021 and the three months ended December 31, 2020, respectively. The decrease in the depletion rate was primarily a result of the impairment charge of $60.7 million for the three months ended

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December 31, 2020, resulting in lower depletable cost (or amortizable base) in the calculation of the depletion rate for the three months ended March 31, 2021.

Impairment of oil and gas properties. At March 31, 2021, the net capitalized costs of our oil and gas properties was less than the ceiling test. As a result, we did not record an impairment charge of our oil and gas properties, net for the three months ended March 31, 2021. In determining the ceiling test at March 31, 2021, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $40.01 per Bbl and $2.18 per MMBtu, respectively, which is an increase of 1% and 9%, respectively, from the three months ended December 31, 2020 SEC oil price and SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively. At December 31, 2020, the net capitalized costs of our oil and gas properties exceeded the ceiling test primarily due to the decline in oil and gas prices and reduction in operator activity. As a result, we recorded a $60.7 million impairment of our oil and gas properties, net for the three months ended December 31, 2020.

General and administrative and share-based compensation. General and administrative expense (before share-based compensation) decreased 2% for the three months ended March 31, 2021, compared to the three months ended December 31, 2020.

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. Share-based compensation expense for the three months ended December 31, 2020 was $1.8 million, net of $0.4 million of share-based compensation cost capitalized to unevaluated property and $1.1 million of share-based compensation cost capitalized to evaluated property. The sequential increase in share-based compensation expense of $0.5 million was primarily due to additional grants of RSUs that were granted during the three months ended March 31, 2021. See table below for additional details.

						Three Months Ended
(In thousands)						March 31, 2021						December 31, 2020						Variance
Incentive Units						$	178					$	178					$	—
RSAs						134						177						(43)
RSUs						2,542						1,905						637
PSUs						1,079						1,103						(24)
Capitalized share-based compensation						(1,633)						(1,526)						(107)
Total share-based compensation expense						$	2,300					$	1,837					$	463

Interest expense, net. Interest expense, net increased $0.1 million for the three months ended March 31, 2021 compared to the three months ended December 31, 2020, primarily due to an increase in our weighted average debt outstanding on our revolving credit facility from $9.6 million to $23.9 million as shown in the table below.

						Three Months Ended
(In thousands, except for interest rate)						March 31, 2021						December 31, 2020						Variance
Interest expense - revolving credit facility						$	113					$	47					$	66
Commitment fees						104						120						(16)
Amortization of loan closing costs						58						59						(1)
Interest income						(8)						(31)						23
Total interest expense, net						$	267					$	195					$	72
Total weighted average interest rate						1.83		%				1.91		%
Total weighted average debt balance						$	23,911					$	9,565

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Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

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:

						Three Months Ended March 31,
(Dollars in thousands, except for realized prices and unit expenses)						2021						2020						Variance
Production:
Oil (MBbls)						411						517						(106)						(21)		%
Natural gas (MMcf)						1,451						1,584						(133)						(8)		%
NGLs (MBbls)						151						165						(14)						(8)		%
Equivalents (MBoe)						804						946						(142)						(15)		%
Equivalents per day (Boe/d)						8,931						10,401						(1,470)						(14)		%
Revenues:
Oil sales						$	22,813					$	23,587					$	(774)					(3)		%
Natural gas sales						5,437						2,791						2,646						95		%
NGL sales						3,926						1,996						1,930						97		%
Total mineral and royalty revenue						$	32,176					$	28,374					$	3,802					13		%
Lease bonus and other revenue						1,597						3,906						(2,309)						(59)		%
Total revenues						$	33,773					$	32,280					$	1,493					5		%
Realized prices
Oil ($/Bbl)						$	55.55					$	45.61					$	9.94					22		%
Natural gas ($/Mcf)						3.75						1.76						1.99						113		%
NGLs ($/Bbl)						25.97						12.07						13.90						115		%
Equivalents ($/Boe)						$	40.03					$	29.98					$	10.05					34		%
Operating expenses:
Gathering, transportation and marketing						$	1,733					$	1,779					$	(46)					(3)		%
Severance and ad valorem taxes						1,833						1,752						81						5		%
Depreciation, depletion, and amortization						9,367						12,826						(3,459)						(27)		%
General and administrative (before share-based compensation)						3,142						3,626						(484)						(13)		%
Total operating expenses (before share-based compensation)						$	16,075					$	19,983					$	(3,908)					(20)		%
Share-based compensation						2,300						1,884						416						22		%
Total operating expenses						$	18,375					$	21,867					$	(3,492)					(16)		%
Other expenses:
Interest expense, net						$	267					$	32					$	235					***
Total other expenses						$	267					$	32					$	235					***

*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300%.

						Three Months Ended March 31,
Unit Expenses ($/Boe)						2021						2020						Variance
Gathering, transportation and marketing						$	2.16					$	1.88					$	0.28					15		%
Severance and ad valorem taxes						2.28						1.85						0.43						23		%
Depreciation, depletion and amortization						11.65						13.55						(1.90)						(14)		%
General and administrative (before share-based compensation)						3.91						3.83						0.08						2		%
General and administrative, share-based compensation						2.86						1.99						0.87						44		%
Interest expense, net						0.33						0.03						0.30						***

*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300%.

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Revenues

Total revenues for the three months ended March 31, 2021 increased 5%, or $1.5 million, compared to the three months ended March 31, 2020. The increase was attributable to a $3.8 million increase in mineral and royalty revenues offset by a $2.3 million decrease in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 34% increase in realized commodity prices, resulting in an increase in royalty revenues of $8.1 million. This was partially offset by a 14% decrease in production volumes to 8,931 Boe/d, resulting in an decrease in revenues of $4.3 million. The decrease in production volumes was primarily due to the reduction in drilling activity during the second half of 2020. In addition, operator production curtailments in Texas and Oklahoma resulting from the February 2021 Winter Storm Uri contributed to the decrease in production volumes in the first quarter 2021.

Oil revenues for the three months ended March 31, 2021 decreased 3%, or $0.8 million, compared to the three months ended March 31, 2020. The decrease in oil revenues was attributable to the 21% decrease in oil production volumes to 4,563 barrels per day, resulting in a $4.9 million decrease in oil revenues. This was partially offset by the 22% increase in realized oil prices to $55.55 per barrel, resulting in an increase in revenues of $4.1 million.

Natural gas revenues for the three months ended March 31, 2021 increased 95%, or $2.6 million, compared to the three months ended March 31, 2020. The increase in natural gas revenues was attributable to the 113% increase in realized natural gas prices to $3.75 per Mcf, resulting in an increase in revenues of $2.9 million. This was partially offset by the 8% decrease in natural gas production volumes to 16,126 Mcf/d, resulting in a $0.3 million decrease in natural gas revenues.

NGL revenues for the three months ended March 31, 2021 increased 97%, or $1.9 million, compared to the three months ended March 31, 2020. The increase in NGL revenues was attributable to the 115% increase in NGL prices to $25.97 per barrel, resulting in an increase in NGL revenues of $2.1 million. This was partially offset by the 8% decrease in NGL volumes to 1,680 barrels per day, resulting in a decrease in revenues of $0.2 million.

Lease Bonus and Other Revenues

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The decrease in revenues from lease bonus payments for the three months ended March 31, 2021 is primarily attributable to the decrease in leasing activity in the Permian Basin. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Operating Expenses

Gathering, transportation and marketing ("GTM") expenses. For the three months ended March 31, 2021, GTM expenses decreased 3% compared to the three months ended March 31, 2020 primarily due to the 14% decrease in production volumes.

Severance and ad valorem taxes. For the three months ended March 31, 2021, severance and ad valorem taxes increased 5% compared to the three months ended March 31, 2020, due to the 13% increase in mineral and royalty revenues which was primarily due to an increase in realized commodity prices of 34%, partially offset by a 14% decrease in production volumes.

Depreciation, depletion and amortization. DD&A expense decreased 27%, or $3.5 million, for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. Lower production volumes decreased our depletion expense by $1.8 million and a lower depletion rate decreased our depletion expense by $1.1 million. The depletion rate was $11.58 per Boe and $12.94 per Boe for the three months ended March 31, 2021 and 2020, respectively. The decrease in the depletion rate was primarily a result of the impairment charge of $79.6 million for the year ended December 31, 2020, resulting in lower depletable cost (or amortizable base) in the calculation of the depletion rate for the three months ended March 31, 2021.

General and administrative and share-based compensation. General and administrative expense (before share-based compensation) decreased 13%, or $0.5 million, for the three months ended March 31, 2021, compared to the three months ended March 31, 2020 as a result of the Company's ongoing efforts to reduce its overall general and administrative expenses.

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. Share-based compensation expense for the three months ended March 31, 2020 was $1.9 million, net of $0.9 million of share-based compensation cost capitalized to unevaluated property and $0.6 million of share-based compensation cost

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capitalized to evaluated property. The increase in share-based compensation expense of $0.4 million was primarily due to additional grants of RSUs that were granted during the three months ended March 31, 2021. See table below for further details.

						Three months ended March 31,
(In thousands)						2021						2020						Variance
Incentive Units						$	178					$	178					$	—
RSAs (1)						134						700						(566)
RSUs						2,542						1,594						948
PSUs						1,079						930						149
Capitalized share-based compensation						(1,633)						(1,518)						(115)
Total share-based compensation expense						$	2,300					$	1,884					$	416

(1)During the three months ended March 31, 2020, share-based compensation cost included $0.5 million associated with the accelerated vesting of 30,174 RSAs for certain employees who retired in February 2020.

Interest expense, net. Interest expense, net increased $0.2 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020. See table below for further details.

						Three months ended March 31,
(In thousands, except for interest rate)						2021						2020						Variance
Interest expense - revolving credit facility						$	113					$	—					$	113
Commitment fees						104						162						(58)
Amortization of loan closing costs						58						101						(43)
Interest income						(8)						(231)						223
Total interest expense, net						$	267					$	32					$	235
Total weighted average interest rate						1.83		%				—		%
Total weighted average debt balance						$	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

On June 12, 2020, Brigham Minerals completed an offering of 6,600,000 shares of its Class A common stock (the "June 2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the “June 2020 Selling Shareholders”), and 4,872,669 of which represented shares issued upon redemption of an equivalent number of the June 2020 Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $13.75 per share. Brigham Minerals did not sell any shares of its common stock in the June 2020 Secondary Offering and did not receive any proceeds pursuant to the June 2020 Secondary Offering.

On September 15, 2020, Brigham Minerals completed an offering of 5,021,140 shares of its Class A common stock, including 654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-allotments (the "September 2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the "September 2020 Selling Shareholders"), and 3,062,011 of which represented shares issued upon redemption of an equivalent number of the September 2020 Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $8.20 per share. Brigham Minerals did not sell any shares of its Class A common stock in the September 2020 Secondary Offering and did not receive any proceeds pursuant to the September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham Minerals repurchased 436,630 shares of its Class A common stock from the September 2020 Selling Shareholders in a privately negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020 Selling Shareholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding number of Brigham LLC Units held by Brigham Minerals).

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As of March 31, 2021, Brigham Minerals owned a 77% interest in Brigham LLC and the Brigham LLC Unit Holders owned 23% 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 Company's Brigham LLC Unit Holders, collectively owned 16.9% of the outstanding voting stock of Brigham Minerals as of March 31, 2021.

As of March 31, 2020, Brigham Minerals owned a 60.1% interest in Brigham LLC and the Brigham LLC Unit Holders owned 39.9% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Warburg Pincus LLC, Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Company's Brigham LLC Unit Holders, collectively owned 39.1% of the outstanding voting stock of Brigham Minerals as of March 31, 2020.

The change in ownership interest in Brigham LLC from March 31, 2020 to March 31, 2021 impacts the attribution of net income between Brigham Minerals' shareholders and Brigham LLC Unit Holders. Brigham LLC Unit Holders' interest is classified as non-controlling interest in the condensed consolidated balance sheets of Brigham Minerals. See "Note 9—Temporary equity and Non-controlling interest" for further details.

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 we may enter into in the future and additional issuances of debt or equity securities. As a result of the COVID-19 pandemic and the decline in commodities prices in 2020, coupled with many of our operators announcing significant reductions in projected capital expenditures in 2021 and beyond, our revenues and cash flows from operations have been and may continue to 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 shareholders and for investing in our business, specifically the acquisition of additional mineral and royalty interests. In connection with the ongoing COVID-19 pandemic and the announced reductions in projected capital expenditures by our operators, our cash flows from operations have been and may continue to be negatively impacted, and as a result, the dividend amount we are able to pay our shareholders has been and may also continue to 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, 2021, we deployed approximately $23.5 million for acquisition-related capital expenditures, inclusive of a $1.6 million capitalized share-based compensation cost. 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, 2021, we believe that our retained cash flow from operations, lease bonus 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.

As of March 31, 2021, our liquidity was as follows:

						(In millions)
Cash and cash equivalents						$5.6
Revolving credit facility availability						$103.0
Total Liquidity						$108.6

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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 $165 million. In addition to the increase in the borrowing base, there are several proposed changes to the terms of the revolving credit facility, including various affirmative, negative, and financial maintenance covenants.

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $21.9 million at March 31, 2021, as compared to $22.6 million at December 31, 2020. 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 $5.6 million and $9.1 million at March 31, 2021 and December 31, 2020, respectively. The decrease in cash and cash equivalents was primarily due to acquisitions made and payment of dividends to our shareholders during the three months ended March 31, 2021. See "Note 4—Acquisitions" 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, 2021:

Declaration Date

Record Date

Payment Date

Dividend Amount

Dividends paid (in thousands) (1)

February 19, 2021

March 19, 2021

March 26, 2021

$

0.26

11,336

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

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, 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:

						Three Months Ended March 31,
(In thousands)						2021						2020
Net cash provided by operating activities						$	22,089					$	27,150
Net cash used in investing activities						(21,936)						(23,882)
Net cash used in financing activities						(3,737)						(23,295)

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020

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 decrease in net cash provided by operating activities for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 is primarily due to a $3.3

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million change in working capital due to increased accounts receivables as a result of higher commodity prices and decreased account payable due the Company’s ongoing cost reduction initiatives.

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, 2021, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $21.9 million. For the three months ended March 31, 2020, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests of $25.3 million. The decrease in investing activities for the three months ended March 31, 2021 compared to the three months ended March 31, 2020 was primarily as a result of the market challenges associated with the COVID-19 pandemic and the decrease in oil prices. See "Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Market Environment and COVID-19” for further discussion.

Net cash used in financing activities

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. This was partially offset by borrowings under our revolving credit facility of $12.0 million. Net cash used in financing activities for the three months ended March 31, 2020 was primarily due to the dividends paid to holders of our Class A common stock of $13.0 million and distributions to holders of temporary equity of $10.1 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 substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including 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 May and November of each year. 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, 2021 is 1.83%. As of March 31, 2021, the elected borrowing base on our revolving credit facility was $135.0 million, with outstanding borrowings of $32.0 million, resulting in $103.0 million available for future borrowings. 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 $165 million. In addition to the increase in the borrowing base, there are several proposed changes to the terms of the revolving credit facility, including various affirmative, negative, and financial maintenance covenants.

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, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans, 1.750% to 2.750%. 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 revolving credit facility. 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.

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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.

Off-Balance Sheet Arrangements

As of March 31, 2021, we did not have any material off-balance sheet arrangements.

Contractual Obligations

A summary of our contractual obligations as of March 31, 2021, is provided in the following table.

						By Year:
(In thousands)						2021						2022						2023						2024						2025						Thereafter						Total
Long-term debt obligations (1) (2)						$	—					$	—					$	—					$	32,000					$	—					$	—					$	32,000
Office lease						956						1,310						1,347						1,384						1,419						2,251						8,667
Total						$	956					$	1,310					$	1,347					$	33,384					$	1,419					$	2,251					$	40,667

(1) As of March 31, 2021, we had $32.0 million outstanding under our revolving credit facility and $103.0 million of additional borrowing capacity.

(2) Does not include future unutilized fees, amortization of deferred financing costs, interest expense or other fees related to our revolving credit facility because we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

Critical Accounting Policies and Related Estimates

As of March 31, 2021, 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 $77.41 per barrel in June 2018, and as of March 31, 2021, the posted price for oil was $59.19 per barrel. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise declined 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, 2021, the Henry Hub spot market price of natural gas was $2.52 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 $0.4 million change in our oil revenues for the three months ended March 31, 2021. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million change in our natural gas revenues for the three months ended March 31, 2021. A $1.00 per barrel change in NGL

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prices would have resulted in a $0.1 million change in our NGL revenues for the three months ended March 31, 2021. Total revenues for the three months ended March 31, 2021 was comprised of 68% from oil sales, 15% from natural gas sales, and 12% from NGL sales.

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 had no 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 do 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.

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, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans, 1.750% to 2.750%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months, for adjusted LIBOR rate loans. Interest on adjusted base rate loans is payable quarterly in arrears, and interest on adjusted LIBOR rate loans 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, 2021 is 1.83%. As of March 31, 2021, the elected borrowing base on our revolving credit facility was $135.0 million, with outstanding borrowings of $32.0 million, resulting in $103.0 million available for future borrowings. A 1-percentage-point increase in our interest rate would have increased our interest expense by $0.1 million for the three months ended March 31, 2021.

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, 2021. 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, 2021.

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 2021 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
2.1						Master Reorganization Agreement, dated April 17, 2019, by and among Brigham Minerals, Inc. and the other parties named therein (1)
2.2						Contribution and Distribution Agreement, dated April 23, 2019, by and among Brigham Minerals, Inc. and the parties named therein (2)
3.1						Amended and Restated Certificate of Incorporation of Brigham Minerals, Inc., filed with the Secretary of State of the State of Delaware on April 23, 2019. (2)
3.2						Amended and Restated Bylaws of Brigham Minerals, Inc., effective April 23, 2019. (2)
10.1						Indemnification Agreement (Jon-Al Duplantier) (3)
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, 2021 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.

(1)    Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on April 22, 2019.

(2)    Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on April 29, 2019.

(3)    Incorporated by reference to the registrant's Current Report on Form 8-K, filed on February 24, 2021.

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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 6, 2021			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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