MNRL Sub Inc. - Quarter Report: 2020 June (Form 10-Q)

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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 June 30, 2020

☐ 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 39,296,944 shares of Class A common stock and 17,612,638 shares of Class B common stock outstanding as of August 10, 2020.

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BRIGHAM MINERALS, INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2020

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 and Combined Balance Sheets a t June 3 0 , 2020 and December 31, 2019	1
	Condensed Consolidated and Combined Statement of Operations for the Three and Six Months Ended June 3 0 , 2020 and 2019	2
	Condensed Consolidated and Combined Statement of Changes in Shareholders' and Members' Equity for the Three and Six Months Ended June 3 0 , 2020 and 2019	3
	Condensed Consolidated and Combined Statement of Cash Flows for the Six Months Ended June 3 0 , 2020 and 2019	5
	Notes to Condensed Consolidated and Combined Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	43

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	44

Item 6.	Exhibits	50
	SIGNATURES	51

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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.

iii

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 (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, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 (the "Q1 2020 Quarterly Report") and in our Annual Report on Form 10-K for the year ended December 31, 2019 (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 effects of current or future litigation, including recent U.S. Supreme Court ruling involving Muscogee (Creek) Nation reservation in Eastern Oklahoma;

•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;

•the actions of the Organization of Petroleum Exporting Countries 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 in whether development projects will be pursued;

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

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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 Q1 2020 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 AND COMBINED BALANCE SHEETS


	June 30,		December 31,
(In thousands, except share amounts)	2020		2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	16,465	$	51,133

Accounts receivable	18,011		30,291
Prepaid expenses and other	2,281		1,688


Total current assets	36,757		83,112
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property	307,809		291,664
Evaluated property	464,630		449,061
Less accumulated depreciation, depletion, and amortization	(85,986)		(61,103)
Total oil and gas properties, net	686,453		679,622
Other property and equipment	5,381		5,095
Less accumulated depreciation	(4,410)		(3,703)
Other property and equipment, net	971		1,392

Deferred tax asset	17,783		18,823
Other assets, net	928		1,213
Total assets	$	742,892	$	784,162

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	8,197	$	11,533


Total current liabilities	8,197		11,533
Long-term bank debt	—		—

Other non-current liabilities	1,747		803

Temporary equity	214,146		454,507
Shareholders' equity:

Preferred stock, $0.01 par value; 50,000,000 authorized; no shares issued and outstanding at June 30, 2020 and December 31, 2019	—		—
Class A common stock, $0.01 par value; 400,000,000 authorized, 39,296,944 shares issued and outstanding at June 30, 2020; 400,000,000 authorized, 34,040,934 issued and outstanding at December 31, 2019	393		340
Class B common stock, $0.01 par value; 150,000,000 authorized, 17,612,638 shares issued and outstanding at June 30, 2020; 150,000,000 authorized, 22,847,045 shares issued and outstanding at December 31, 2019	—		—
Additional paid-in capital	551,165		323,578

Accumulated deficit	(32,756)		(6,599)
Total shareholders' equity attributable to Brigham Minerals Inc.	518,802		317,319


Total liabilities and shareholders' equity	$	742,892	$	784,162

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands, except per share data)	2020		2019		2020		2019
REVENUES
Mineral and royalty revenues	$	12,543	$	23,049	$	40,917	$	40,639
Lease bonus and other revenues	62		1,480		3,968		2,155
Total revenues	12,605		24,529		44,885		42,794



OPERATING EXPENSES
Gathering, transportation and marketing	1,625		1,523		3,404		2,637
Severance and ad valorem taxes	1,034		1,450		2,786		2,829
Depreciation, depletion and amortization	11,200		6,760		24,026		11,876
General and administrative	5,890		9,762		11,400		11,711
Total operating expenses	19,749		19,495		41,616		29,053
NET (LOSS) INCOME FROM OPERATIONS	(7,144)		5,034		3,269		13,741
Gain (loss) on derivative instruments, net	—		73		—		(612)
Interest expense, net	(545)		(1,270)		(577)		(5,095)
Loss on extinguishment of debt	—		(6,933)		—		(6,933)

Other income, net	23		6		25		35
(Loss) income before income taxes	(7,666)		(3,090)		2,717		1,136
Income tax (benefit) expense	(850)		117		732		307
NET (LOSS) INCOME	$	(6,816)	$	(3,207)	$	1,985	$	829
Less: net income attributable to predecessor	—		(1,590)		—		(5,092)
Less: net loss (income) attributable to temporary equity	2,766		2,941		(1,329)		2,941
Net (loss) income attributable to Brigham Minerals, Inc. shareholders	$	(4,050)	$	(1,856)	$	656	$	(1,322)

NET (LOSS) INCOME PER COMMON SHARE
Basic	$	(0.11)	$	(0.12)	$	0.02	$	(0.24)
Diluted	$	(0.11)	$	(0.12)	$	0.02	$	(0.25)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	35,282		17,819		34,631		8,959
Diluted	35,282		41,460		34,631		20,806

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN SHAREHOLDERS' AND MEMBERS' EQUITY

(Unaudited)


	Members' Contributed Capital		Class A Common Stock							Class B Common Stock							Additional Paid-In Capital		Accumulated Deficit	Total Shareholders' Equity
(In thousands)				Shares			Amount		Shares			Amount
Balance - December 31, 2019	$	—	34,041		$	340		22,847		$	—		$	323,578	$	(6,599)	$	317,319
Shares surrendered for tax withholdings 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	—		—		—			—		—			—		(12,945)		(12,945)
Dividend equivalent rights declared	—		—		—			—		—			—		(596)		(596)
Net income attributable to shareholders	—		—		—			—		—			—		4,706		4,706
Adjustment of temporary equity to carrying value	—		—		—			—		—			206,017		—		206,017
Balance - March 31, 2020	$	—	34,174		$	342		22,707		$	—		$	534,725	$	(15,434)	$	519,633
Shares surrendered for tax withholdings on vested equity awards	—		(11)		—			—		—			(185)		—		(185)
Conversion of shares of Class B Common Stock to Class A Common Stock	—		5,094		51			(5,094)		—			51,518		—		51,569
Deferred tax liability arising from Conversion of shares of Class B Common Stock to Class A Common Stock	—		—		—			—		—			(780)		—		(780)
Share-based compensation	—		50		—			—		—			3,332		—		3,332
Restricted stock forfeited	—		(9)		—			—		—			—		—		—
Dividends declared	—		—		—			—		—			—		(12,710)		(12,710)
Dividend equivalent rights declared	—		—		—			—		—			—		(562)		(562)
Net loss attributable to shareholders	—		—		—			—		—			—		(4,050)		(4,050)
Adjustment of temporary equity to redemption value	—		—		—			—		—			(37,445)		—		(37,445)





Balance - June 30, 2020	$	—	39,298		$	393		17,613		$	—		$	551,165	$	(32,756)	$	518,802

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	Members' Contributed Capital		Class A Common Stock							Class B Common Stock							Additional Paid-In Capital		Accumulated Deficit	Total Shareholders' and Members' Equity
(In thousands)				Shares			Amount		Shares			Amount
Balance—December 31, 2018	$	208,728	—		$	—		—		$	—		$	(3,057)	$	168,277	$	373,948
Net income attributable to shareholders	—		—		—			—		—			—		534		534
Net income attributable to predecessor	—		—		—			—		—			—		3,502		3,502
Balance—March 31, 2019	$	208,728	—		$	—		—		$	—		$	(3,057)	$	172,313	$	377,984
Net income attributable to shareholders	—		—		—			—		—			—		314		314
Net income attributable to predecessor	—		—		—			—		—			—		1,590		1,590
Balance prior to corporate reorganization and IPO	$	208,728	—		$	—		—		$	—		$	(3,057)	$	174,217	$	379,888
Conversion of PE Units for Class A Common Stock and Class B Common Stock	(208,728)		5,322		53			28,778		—			380,205		(171,530)		—
Issuance of common stock in IPO, net of offering cost	—		16,675		167			—		—			274,746		—		274,913
Deferred tax asset arising from the IPO	—		—		—			—		—			13,664		—		13,664
Reclassification of noncontrolling interests to temporary equity	—		—		—			—		—			(518,000)		—		(518,000)
Share-based compensation	—		—		—			—		—			7,505		—		7,505


Net income attributable to shareholders	—		—		—			—		—			—		(2,170)		(2,170)
Adjustment of temporary equity to redemption value	—		—		—			—		—			(97,344)		—		(97,344)




Balance—June 30, 2019	$	—	21,997		$	220		28,778		$	—		$	57,719	$	517	$	58,456

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

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BRIGHAM MINERALS, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENT OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In thousands)	2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,985	$	829
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization	24,026		11,876
Share-based compensation expense	3,736		6,495
Loss on extinguishment of debt	—		6,933
Amortization of debt issuance costs	485		291
Deferred income taxes	463		66
Loss on derivative instruments, net	—		612
Net cash received for derivative settlements	—		238
Bad debt expense	299		293
Changes in operating assets and liabilities:
Decrease in accounts receivable	11,980		185
(Increase)/Decrease in other current assets	(592)		1,268

(Decrease)/Increase in accounts payable and accrued liabilities	(3,509)		481
Decrease in other long-term liabilities	(256)		—
Net cash provided by operating activities	$	38,617	$	29,567
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties	(28,755)		(81,053)
Additions to other fixed assets	(286)		(113)
Proceeds from sale of oil and gas properties, net	1,565		2,001


Net cash used in investing activities	$	(27,476)	$	(79,165)
CASH FLOWS FROM FINANCING ACTIVITIES


Payments of short-term debt	—		(4,596)

Payments of long-term debt	—		(195,404)
Borrowing of long-term debt	—		25,000
Payment of debt extinguishment fees	—		(2,090)
Proceeds from issuance of Class A common stock	—		278,541

Dividends paid	(25,772)		—
Distribution to holders of temporary equity	(19,834)		—
Debt issuance costs	(203)		(1,144)
Net cash (used in) provided by financing activities	$	(45,809)	$	100,307
Decrease in cash and cash equivalents and restricted cash	(34,668)		50,709
Cash and cash equivalents and restricted cash, beginning of period	51,133		32,018
Cash and cash equivalents and restricted cash, end of period	$	16,465	$	82,727

Supplemental disclosure of noncash activity:


Accrued capital expenditures	$	23	$	1,679
Capitalized share-based compensation cost	$	2,998	$	1,010
Temporary equity cumulative adjustment to redemption value	$	(168,572)	$	97,344
Supplemental cash flow information:
Cash payments for loan commitment fees and interest	$	442	$	5,490
Cash taxes paid	$	113	$	283

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

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(Unaudited)

1.Business and Basis of Presentation

Description of the Business

Brigham Minerals, Inc. (together with its wholly owned subsidiaries, “Brigham Minerals” or the “Company”) is a Delaware corporation formed in June 2018 to become a holding company. Brigham Minerals acquired an indirect interest in Brigham Resources, LLC (“Brigham Resources”), our predecessor, on July 16, 2018 in a series of restructuring transactions pursuant to which certain entities affiliated with Warburg Pincus LLC (“Warburg Pincus”) contributed all of their respective interests in the entities through which they held interests in Brigham Resources to Brigham Minerals in exchange for all of the outstanding shares of common stock of Brigham Minerals (the “July 2018 Restructuring”). As a result of such restructuring transactions, Brigham Minerals became wholly owned by an entity affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a 16.5% membership interest in Brigham Resources. The remaining outstanding membership interests of Brigham Resources remained with certain other entities affiliated with Warburg Pincus, Yorktown Partners LLC and Pine Brook Road Advisors, LP, Brigham Minerals’ management and its other investors (collectively, the “Original Owners”).

On November 20, 2018, Brigham Resources underwent a second series of restructuring transactions (the “November 2018 Restructuring”). In the November 2018 Restructuring, Brigham Resources became a wholly owned subsidiary of Brigham Minerals Holdings, LLC (“Brigham LLC”), which was a wholly owned subsidiary of Brigham Equity Holdings, LLC (“Brigham Equity Holdings”), and Brigham Equity Holdings became wholly owned by the owners of Brigham Resources immediately prior to such restructuring, directly or indirectly, through Brigham Minerals. As a result of the foregoing transactions, there was no change in the control or economic interests of the Original Owners and Brigham Minerals in Brigham Resources, although their ownership became indirect through Brigham Equity Holdings and its wholly owned subsidiary, Brigham LLC. The July 2018 Restructuring and the November 2018 Restructuring are collectively referred to herein as the “2018 corporate reorganizations.”

Brigham Resources wholly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”), which acquire and actively manage a portfolio of mineral and royalty interests. The Minerals Subsidiaries are Brigham Resources’ sole material assets.

Initial Public Offering

In April 2019, Brigham Minerals completed the initial public offering (the "IPO") of 16,675,000 shares of Class A common stock at a price to the public of $18.00 per share. This resulted in net proceeds of approximately $273.4 million, after deducting underwriting commissions and discounts and offering expenses, which proceeds were used to repay $200.0 million of existing indebtedness and to fund mineral and royalty acquisitions. As a result of the IPO and the corporate restructuring described in "Note 10—Temporary Equity", Brigham Minerals became a holding company whose sole material asset consisted of a 43.3% interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly owned subsidiary, Brigham Resources.

December 2019 Offering

On December 16, 2019, Brigham Minerals completed an offering of 12,650,000 shares of its Class A common stock (the "December 2019 Offering"), including 6,000,000 shares issued and sold by Brigham Minerals and an aggregate of 6,650,000 shares sold by certain shareholders of the Company (the "Selling Shareholders"), of which 5,496,813 represents shares issued upon redemption of an equivalent number of their common units in Brigham LLC (the "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 $18.10 per share ($17.376 per share net of underwriting discounts and commissions). After deducting underwriting discounts, commissions and offering expenses, Brigham Minerals received net proceeds of approximately $102.7 million which were used to repay $80.0 million of existing indebtedness and to fund future mineral and royalty acquisitions. Brigham Minerals did not receive any proceeds from the sale of shares of Class A common stock by the Selling Shareholders.

June 2020 Secondary Offering

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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.

Following the completion of the June 2020 Secondary Offering and as of June 30, 2020, Brigham Minerals owned a 69.1% interest in Brigham LLC and the Original Owners owned 30.9% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Warburg Pincus, Yorktown Partners LLC and Pine Brook Road Advisors, LP (collectively, the "Sponsors"), which are a subset of the Company's Original Owners, collectively owned 27.5% of the outstanding voting stock of Brigham Minerals as of June 30, 2020.

Basis of Presentation

Subsequent to the July 2018 Restructuring and prior to the IPO, Brigham Minerals used the equity method of accounting for its investment in Brigham Resources, its predecessor, because its 16.5% ownership in Brigham Resources provided Brigham Minerals with significant influence, but not with a controlling financial interest or the ability to direct the most significant activities of Brigham Resources. Upon the completion of the IPO, Brigham Minerals indirectly owned an approximate 43.3% interest of Brigham Resources and 100% of the voting rights and consolidated the results of operations of Brigham Resources. In order to furnish comparative financial information, the accompanying consolidated and combined financial statements and related notes of Brigham Minerals for periods prior to the IPO, including the 2019 amounts presented, have been retrospectively recast to include the combined historical financial information of both Brigham Resources (at historical carrying values) and Brigham Minerals, taking into account state and federal income taxes and liabilities associated with Brigham Minerals. All intercompany transactions between Brigham Minerals and Brigham Resources have been eliminated. Because Brigham Minerals acquired an interest in Brigham Resources as part of certain reorganization transactions in 2018, net income is attributable to stockholders of Brigham Minerals in addition to its predecessor beginning in 2018.

The accompanying unaudited condensed, consolidated and combined interim financial statements of Brigham Minerals have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), except that, in accordance with the instructions to Form 10-Q, they do not include all of the notes required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim financial statements should be read in conjunction with our audited financial statements included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on February 28, 2020 (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 and six months ended June 30, 2020 are not necessarily indicative of the results to be expected for the entire fiscal year ending December 31, 2020. Brigham Minerals operates in one segment: oil and natural gas exploration and production.

2.Summary of Significant Accounting Policies

Use of Estimates

These condensed, consolidated and combined 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 and combined 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 and combined 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

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(Unaudited)

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. (“CG&A”), an 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, valuation of derivative instruments, 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, 2019, presented in the Annual Report. There have been no changes in such policies or the application of such policies during the three and six months ended June 30, 2020.

Recently Adopted Accounting Standards

Restricted cash includes cash that is contractually restricted for its use through an agreement with a non-related party. On December 31, 2019, the Company adopted ASU 2016-18, Statement of Cash Flows, which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. The ASU requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows.

The adoption resulted in a decrease in reported investing cash flow of $33,000 for the six months ended June 30, 2019. The June 30, 2019 accompanying statement of cash flow that was adjusted as a result of adoption of ASU 2016-18 is summarized below:


	Six Months Ended June 30, 2019
(In thousands)	As reported		As adjusted
Changes in restricted cash held in escrow for acquisitions	$	33	$	—
Net cash used in investing activities	$	(79,132)	$	(79,165)

Decrease in cash, cash equivalents and restricted cash	50,742		50,709
Cash, cash equivalents and restricted cash, beginning of period	$	31,985	$	32,018

Accounts Receivables

As of June 30, 2020 and December 31, 2019, accounts receivables was comprised of the following:


(In thousands)	June 30, 2020		December 31, 2019
Accounts receivables
Oil and gas sales	$	16,021	$	27,888
Reserve for bad debt	(855)		(556)
Other	2,845		2,959
Total accounts receivables	$	18,011	$	30,291

Concentration of Credit Risk and Significant Customers

Financial instruments that potentially subject Brigham Minerals to concentrations of credit risk consist of cash, accounts receivable, commodity derivative financial instruments 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.

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(Unaudited)

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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Occidental Petroleum Corp	15	%	22	%	14	%	21	%
Exxon Mobil Corp	12	%	3	%	9	%	4	%
Royal Dutch Shell PLC	10	%	—	%	14	%	—	%

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 and six months ended June 30, 2020, we received revenues from over 150 operators with approximately 64% and 63%, respectively, of revenues coming from the top ten operators on our properties.

Recently Issued Accounting Standards Not Yet Adopted

Brigham Minerals’ status as an emerging growth company 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.

In February 2016, 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 and early adoption is permitted. We are currently evaluating the impact that the adoption of this update will have on our condensed consolidated and combined 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 and combined 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, including certain internal costs, are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred. Oil and gas properties as of the dates shown consisted of the following:

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(Unaudited)


(In thousands)	June 30, 2020		December 31, 2019
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property	$	307,809	$	291,664
Evaluated property	464,630		449,061
Total oil and gas properties, at cost	772,439		740,725
Less accumulated depreciation, depletion, and amortization	(85,986)		(61,103)
Total oil and gas properties, net	$	686,453	$	679,622

Capitalized costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $11.1 million and $6.6 million for the three months ended June 30, 2020 and 2019, respectively, and $23.3 million and $11.6 million for the six months ended June 30, 2020 and 2019, respectively. Average depletion of proved properties was $13.74 per Boe and $10.74 per Boe for the three months ended June 30, 2020 and 2019, respectively, and $13.31 per Boe and $10.53 per Boe for the six months ended June 30, 2020 and 2019, respectively.

The costs associated with unevaluated properties primarily consist of acquisition costs and capitalized general and administrative costs. Under the full cost method of accounting, Brigham Minerals capitalizes certain overhead expenses and other internal costs attributable to the acquisition of mineral and royalty interests as part of its investment in oil and gas properties over the periods benefitted by these activities. Capitalized costs do not include any costs related to general corporate overhead or similar activities. Capitalized costs were $2.6 million and $1.6 million for the three months ended June 30, 2020 and 2019, respectively, and $5.0 million and $2.7 million for the six months ended June 30, 2020 and 2019, respectively.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the cost of unevaluated properties (the ceiling limitation). A write-down of the carrying value of the full cost pool 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 limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using the trailing 12-month first day of the month oil ("SEC oil pricing") and natural gas ("SEC gas pricing") average prices, as adjusted for basis or location differentials, held constant over the life of the reserves (net wellhead prices). As of June 30, 2020, the prices used in the calculation of the ceiling test were $47.13 per barrel of oil and $2.08 per MMbtu of natural gas. Using these prices, the ceiling limitation exceeded the net book value of oil and natural gas properties by approximately $15.0 million and no write off was necessary. Using the trailing 12-month first day of the month oil and natural gas average prices for the period from September 1, 2019 to August 1, 2020, of $44.49 per barrel of oil and $2.00 per MMbtu of natural gas, the net book value as of June 30, 2020, exceeds the ceiling limitation of oil and natural gas properties by less than $10.0 million, and therefore, a write off entry may be necessary in the third quarter of 2020. This ceiling limitation does not consider drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, changes in proved undeveloped locations and production occurring subsequent to June 30, 2020 that may require revisions to estimates of proved reserves.

During the three months ended June 30, 2020, Brigham Minerals reduced its proved undeveloped reserves by 839 MBoe due to conversion from proved undeveloped reserves to proved developed reserves within the quarter as well as the 15% reduction in SEC oil pricing over the quarter. During the six months ended June 30, 2020, Brigham Minerals reduced its proved undeveloped reserves by 5,050 MBoe primarily as a result of a decrease in rig activity, conversion from proved undeveloped reserves to proved developed reserves within the six months as well as the 15% reduction in SEC oil pricing over the six months. The reduction in rig activity led to changes in the development timing and a reduction of the number of proved undeveloped locations that Brigham Minerals expects will be developed within five years after the date of booking.

4. Acquisitions and Divestitures

During the six months ended June 30, 2020 and 2019, 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 were funded with proceeds from the December 2019

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Offering for the six months ended June 30, 2020. For the six months ended June 30, 2019, the change in the oil and natural gas property balance were funded with proceeds from the Owl Rock credit facility (as defined below) and the IPO.


	Oil and Gas Properties Acquired						Cash Consideration Paid
(In thousands)	Evaluated		Unevaluated
Quarter Ended March 31, 2020	$	9,471	$	15,947	$	25,418
Quarter Ended June 30, 2020	805		2,493		3,298
Total	$	10,276	$	18,440	$	28,716


	Oil and Gas Properties Acquired						Cash Consideration Paid
(In thousands)	Evaluated		Unevaluated
Quarter Ended March 31, 2019	$	27,929	$	13,403	$	41,332
Quarter Ended June 30, 2019	25,050		14,925		39,975
Total	$	52,979	$	28,328	$	81,307

5. Revenue from contracts with customers

Contract Balances

Oil, natural gas and NGLs 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 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. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. As of June 30, 2020, accounts receivable from oil and gas sales of $16.0 million represent rights to payment for which Brigham Minerals has satisfied its obligations under contracts with customers.

Prior-period performance obligations

As a non-operator, 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 and six months ended June 30, 2020 and 2019, 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. Derivative Instruments

Brigham Minerals periodically uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas sales and thereby achieve a more predictable level of cash flows. None of the derivative instruments are designated as hedges. Brigham Minerals does not enter into derivative instruments for speculative or trading purposes.

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(Unaudited)

Because the counterparties to Brigham Minerals derivative instruments have investment grade credit ratings, Brigham Minerals believes it does not have significant credit risk and does not anticipate nonperformance from its counterparties. Brigham Minerals continually monitors the credit ratings of its counterparties.

Concurrent with the termination of its prior revolving credit facility in July 2018, Brigham Resources posted cash collateral of $1.4 million for its existing WTI fixed price swap contracts. The cash collateral was $1.6 million in May 2019 prior to the termination of the Owl Rock credit facility and was returned to Brigham Resources upon entering into the revolving credit facility. See "Note 8—Long-Term Debt."

Brigham Minerals had no derivative contracts in place as of June 30, 2020 and December 31, 2019. Prior to December 31, 2019, we had certain oil swap contracts based on the NYMEX futures index.

The following table summarizes Brigham Minerals' gain (loss) on derivative instruments, net on its condensed consolidated and combined statement of operations for the three and six months ended June 30, 2020 and 2019:


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2020		2019		2020		2019
Realized gain	$	—	$	40	$	—	$	238
Unrealized gain (loss)	—		33		—		(850)
Combined - realized/unrealized gain (loss)	$	—	$	73	$	—	$	(612)

7. 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 June 30, 2020 and December 31, 2019.

Brigham Minerals had no derivative contracts in place as of June 30, 2020 and December 31, 2019 as disclosed in "Note 6—Derivative Instruments." Commodity derivative instruments are valued using a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and our credit quality for derivative liabilities. As such, these derivative contracts are classified within Level 2.

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(Unaudited)

Brigham Minerals had no transfers into or out of Level 1 and no transfers into or out of Level 2 for the six months ended June 30, 2020 and June 30, 2019.

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.

8. Long-Term Debt

Owl Rock Credit Facility

On July 27, 2018, Brigham Resources entered into a credit facility (the “Owl Rock credit facility”) with Owl Rock Capital Corporation as administrative agent and collateral agent. Brigham Resources used the proceeds from the Owl Rock credit facility to repay the outstanding $70 million of principal under its prior revolving credit facility and to fund mineral and royalty acquisitions. The Owl Rock credit facility was subject to customary fees, guarantees of subsidiaries, restrictions and covenants, including certain restricted payments, and was collateralized by certain oil and natural gas properties of Brigham Resources. The Owl Rock credit facility provided for a $125 million initial term loan, a $75 million delayed draw term loan and a $10 million revolving credit facility, bore interest at a rate per annum equal to, at Brigham Resources’ option, (a) the base rate plus 4.50%, or (b) the adjusted LIBOR rate for such interest period (subject to a 1.00% floor) plus 5.50%, matured on July 27, 2024 and required Brigham Resources to maintain compliance with certain financial and collateral coverage ratios.

On May 7, 2019, the Owl Rock credit facility was terminated and the outstanding balance of $200.0 million was fully repaid using the proceeds generated from the IPO. As a result of the debt repayment, Brigham Minerals recognized a loss on extinguishment of debt of $6.9 million, which consisted of a $4.0 million write-off of capitalized debt issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million.

Revolving Credit Facility

On May 16, 2019 Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as 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 substantially all of Brigham Resources and its domestic subsidiaries’ assets, including substantially all 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. We fully repaid the $80.0 million of outstanding borrowings under our revolving credit facility in December 2019 using a portion of the net proceeds from the December 2019 Offering. As of June 30, 2020, the borrowing base on our revolving credit facility was $135.0 million and there was no outstanding balance. See "Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity—Revolving Credit Facility” for further discussion.

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(Unaudited)

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. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Our revolving credit facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject 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 June 30, 2020, we were in compliance with all covenants in accordance with our revolving credit facility.

9. Shareholders' Equity

Class A Common Stock

Brigham Minerals had approximately 39.3 million shares of its Class A common stock outstanding as of June 30, 2020. Holders of Class A common stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities.

Class B Common Stock

Brigham Minerals had approximately 17.6 million shares of its Class B common stock outstanding as of June 30, 2020. Holders of the Class B common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of Class A common stock and Class B common stock generally vote together as a single class on all matters presented to Brigham Minerals’ stockholders for their vote or approval. Holders of Class B common stock generally do not have any right to receive dividends or distributions upon a liquidation or winding up of Brigham Minerals.

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 Brigham LLC Units), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding RSAs, RSUs, PSUs and unvested Incentive Units (each as defined in "Note 11—Share-Based Compensation"). Brigham Minerals does not use the two-class method because the

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

Class B common stock and the unvested share-based awards are nonparticipating securities. For the three and six months ended June 30, 2020, the Incentive Units, RSUs, RSAs, and shares of Class B common stock were not recognized in dilutive EPS calculations as the effects would have been antidilutive. For the three and six months ended June 30, 2019, the Incentive Units and RSUs were not recognized in dilutive EPS calculations as the effect would have been antidilutive. As of June 30, 2020, 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 and six months ended June 30, 2020, 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 stockholders and EPS computations for the period indicated based on a weighted average number of common stock outstanding for the period:


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands, except per share data)	2020		2019		2020		2019
Basic EPS
Numerator:
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders	$	(4,050)	$	(1,856)	$	656	$	(1,322)
Less: net loss attributable to Brigham Minerals, Inc. shareholders pre-IPO	—		(314)		—		(848)
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders post-IPO	$	(4,050)	$	(2,170)	$	656	$	(2,170)
Denominator:
Basic weighted average shares outstanding	35,282		17,819		34,631		8,959
Basic EPS attributable to Brigham Minerals, Inc. shareholders	$	(0.11)	$	(0.12)	$	0.02	$	(0.24)

Diluted EPS
Numerator:
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders	$	(4,050)	$	(2,170)	$	656	$	(2,170)
Effects of dilutive securities:

Class B common stock	—		(2,941)		—		(2,941)
Diluted net income attributable to Brigham Minerals, Inc. shareholders	$	(4,050)	$	(5,111)	$	656	$	(5,111)
Denominator:
Basic weighted average shares outstanding	35,282		17,819		34,631		8,959
Effects of dilutive securities:

RSAs	—		(77)		—		(77)
Class B common stock	—		23,718		—		11,924
Diluted weighted average shares outstanding	35,282		41,460		34,631		20,806
Diluted EPS attributable to Brigham Minerals, Inc. shareholders	$	(0.11)	$	(0.12)	$	0.02	$	(0.25)

10. Temporary Equity

Temporary equity represents the Original Owners' 30.9% ownership of Brigham LLC, as of June 30, 2020. Each share of Class B common stock does not have any economic rights but entitles its holder to one vote on all matters to be voted on by our stockholders, generally and a redemption right into shares of Class A common stock. As discussed below, following the IPO:

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

•Each holder of Brigham LLC Units (each a "Brigham 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 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 holds, 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 Amended and Restated Limited Liability Company Agreement of Brigham LLC (the "Brigham LLC Agreement"), each Brigham 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 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 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.

Class B common stock is classified as temporary equity in the condensed consolidated and combined balance sheet as, pursuant to the Brigham LLC Agreement, the Redemption Rights of each Brigham Unit Holder for either shares of Class A common stock or an equivalent amount of cash is not solely within Brigham Minerals' control. This is due to the fact that the holders of Class B common stock control a majority of the votes of the board of directors through direct representation on the board of directors, which allows the holders of Class B common stock to influence the determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right. Temporary equity is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital. At March 31, 2020, redemption amount was lower than its carrying value and as a result, the cumulative adjustment of temporary equity to redemption amount was reversed and temporary equity was presented at its carrying value. At June 30, 2020, temporary equity was adjusted to redemption value based on 17,612,638 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $12.16. For the six months ended June 30, 2020, the Company recorded adjustments to the value of temporary equity as presented in the table below:

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NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)


(In thousands)	Temporary Equity Adjustments
Balance - December 31, 2019 (1)	$	454,507
Conversion of Class B common stock to Class A common stock	(1,526)
Net income attributable to temporary equity	4,095
Distribution to holders of temporary equity	(10,240)
Adjustment of temporary equity to carrying value (2)	(206,017)
Balance - March 31, 2020	$	240,819
Conversion of Class B common stock to Class A common stock	(51,569)
Net loss attributable to temporary equity	(2,766)
Distribution to holders of temporary equity	(9,783)
Adjustment of temporary equity to redemption value (3)	37,445
Balance - June 30, 2020	$	214,146

(1)Based on 22,847,045 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $19.89 at December 31, 2019.

(2)In connection with the IPO, the balance transferred from additional paid-in capital to temporary equity was the greater of redemption value or carrying value of the shares of Class B common stock at IPO and included an initial upward adjustment to redemption amount totaling $194.5 million. The redemption amount was lower than the carrying value as of March 31, 2020, and as such, Brigham Minerals adjusted temporary equity to equal carrying value.

(3)Based on 17,612,638 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $12.16 at June 30, 2020.

11. Share-Based Compensation

LLC Incentive Units

As part of the Second Amended and Restated Limited Liability Company Agreement of Brigham Resources, LLC dated May 8, 2015, Brigham Resources authorized 120,000 restricted incentive units for issuance to management, independent directors, employees, and consultants (such incentive units, as converted as described below, the "Incentive Units”). Brigham Resources granted Incentive Units in April 2013 and September 2015 and 2018. In connection with the 2018 corporate reorganizations and the corporate reorganization consummated in connection with Brigham Minerals' IPO (collectively with the 2018 corporate reorganizations, the "corporate reorganization"), these Incentive Units were converted into units in Brigham Equity Holdings, LLC ("Brigham Equity Holdings") with equivalent rights, responsibilities, and preferences. The Incentive Units are subject to vesting as follows: 20% of the Incentive Units were vested on the date of grant and 20% of the Incentive Units vest on each anniversary of the date of grant if the holder remains continuously employed by Brigham Resources or its affiliates through the applicable vesting date. In connection with our IPO, holders of Incentive Units that were vested at such time received one share of Brigham Minerals' Class B common stock and one Brigham LLC Unit for each vested Incentive Unit. Upon vesting of the Incentive Units following the IPO, holders of the Incentive Units will receive one share of Brigham Minerals' Class B common stock and one Brigham LLC Unit for each vested Incentive Unit.

In connection with the completion of the IPO, Brigham LLC and Brigham Equity Holdings discontinued granting new Incentive Units; however Brigham Equity Holdings will continue to administer the existing awards that remain outstanding. As discussed in "Note 10—Temporary Equity," participants may receive one share of Brigham Minerals' Class A common stock in exchange for one share of Class B common stock and one Brigham LLC Unit, or cash at the option of Brigham Minerals. Brigham Minerals accounts for the Incentive Units as compensation cost measured at the fair value of the award on the date of grant. No compensation expense was recognized prior to the IPO because the IPO was not considered probable.

A summary of Incentive Unit activity for the six months ended June 30, 2020 is as follows:

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NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)


	Incentive Units
	Number of Incentive Units	Grant-date Fair Value
Outstanding—January 1, 2020	212,733	$	10.04
Vested	—	—

Outstanding—June 30, 2020	212,733	$	10.04

Brigham LLC used the Black-Scholes option pricing valuation model to assist management in its estimation of the grant-date fair value of the Incentive Units on the respective grant dates during 2013, 2015 and 2018.

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 June 30, 2020, 3,466,893 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.

RSAs are grants of shares of Class A common stock subject to a risk of forfeiture and restrictions on transferability. The share-based compensation expense of such RSAs was determined using the closing price of Class A common stock on April 23, 2019, the date of grant, of $21.25. On April 23, 2019, 312,189 RSAs were granted and 152,742 RSAs vested immediately. During the three months ended March 31, 2020, the compensation committee of the Board of Directors of Brigham Minerals approved the accelerated vesting of 30,174 RSAs for certain employees who retired in February 2020. For the six months ended June 30, 2020, the Company remitted $0.2 million in respect of the employee portion of applicable payroll tax withholding associated with vested RSAs which was satisfied through the surrender of 18,651 RSAs, both of which are presented as an adjustment to additional paid-in-capital and Class A common stock, respectively, included in the Company's condensed consolidated and combined statement of changes in shareholders' and members' equity included within this Quarterly Report. The remaining unvested RSAs generally vest in one-third increments on each of April 23, 2021 and 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 six months ended June 30, 2020.


	Restricted Stock Awards
	Number of RSAs	Grant Date Fair Value
Unvested at January 1, 2020	148,456	$	21.25

Vested	(69,601)	21.25
Forfeited	(9,390)	21.25
Unvested at June 30, 2020	69,465	$	21.25

RSUs 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

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

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.

The following table summarizes activity related to RSUs for the six months ended June 30, 2020.


	Restricted Stock Units
	Number of RSUs	Weighted-Average Grant Date Fair Value
Unvested at January 1, 2020	415,815	$	21.25
Granted	544,045	16.52
Vested	(49,644)	21.25
Forfeited	(12,086)	20.82
Unvested at June 30, 2020	898,130	$	18.39

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 six months ended June 30, 2020. In addition, no PSUs became vested or were forfeited during the six months ended June 30, 2020:


	Performance-Based Restricted Stock Units
	Target PSUs	Estimated Earned PSUs	Grant Date Fair Value
Unvested at January 1, 2020	753,546	450,836	$	20.36
Granted	434,265	174,106	$	15.98
Unvested at June 30, 2020	1,187,811	624,942	$	19.14

Share-Based Compensation Expense

Share-based compensation expense is included in general and administrative expense in the Company's condensed consolidated and combined statement of operations included within this Quarterly Report. Share-based compensation expense recorded for each type of share-based compensation award for the three and six months ended June 30, 2020 and 2019 is summarized in the table below. No share-based compensation expense was incurred prior to the IPO.


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2020		2019		2020		2019
Incentive Units (1) (4)	$	178	$	2,167	$	356	$	2,167
RSAs (1) (5)	190		3,456		891		3,456
RSUs (1)	1,840		1,246		3,434		1,246
PSUs (2)	1,124		636		2,054		636
Capitalized share-based compensation (3)	(1,479)		(1,010)		(2,998)		(1,010)
Total share-based compensation expense	$	1,853	$	6,495	$	3,737	$	6,495

(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.

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BRIGHAM MINERALS, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

(3)During the three and six months ended June 30, 2020, Brigham Minerals capitalized $0.9 million and $1.8 million, respectively, of share-based compensation cost to unevaluated property and $0.6 million and $1.2 million, respectively, of share-based compensation cost to evaluated property.

(4)Includes $2.0 million recorded at IPO. No compensation expense was recorded prior to the IPO because the IPO was not considered probable.

(5)Includes $3.2 million recorded at grant date, associated with 152,742 RSAs, which vested immediately.

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 June 30, 2020, a portion of which will be capitalized:


(In thousands)	Incentive Units		RSAs		RSUs		PSUs		Total
Year
2020	$	356	$	372	$	3,920	$	2,205	$	6,853
2021	712		738		6,827		4,374		12,651
2022	534		228		2,662		966		4,390
Total	$	1,602	$	1,338	$	13,409	$	7,545	$	23,894

12. Income Taxes

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. 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 June 30,									Six Months Ended June 30,
(In thousands, except for tax rate)	2020			2019			2020			2019
Income tax (benefit) expense	$	(850)		$	117		$	732		$	307
Effective tax rate	11.1		%	(3.8)		%	26.9		%	27.0		%

Total income tax expense for the three and six months ended June 30, 2020 and 2019 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of the temporary equity, net income attributable to predecessor, state taxes (net of the anticipated federal benefit), and percentage depletion in excess of basis. The effective tax rate for the three and six months ended June 30, 2019 reflects the Company’s indirect 16.5% interest in Brigham Resources as a result of the 2018 corporate reorganizations. The effective tax rate for the three and six months ended June 30, 2020 reflects the Company’s 69.1% ownership interest in Brigham LLC as a result of the IPO, the December 2019 Offering, the June 2020 Secondary Offering, and certain redemptions of Brigham LLC Units for shares of Class A common stock (and the cancellation of the corresponding number of shares of Class B common stock) completed subsequent to the IPO and prior to June 30, 2020.

13. Commitments and Contingencies

Commitments

Brigham Minerals leases office space under operating leases. Rent expense for the three months ended June 30, 2020 and 2019 was $0.2 million and $0.2 million, respectively. Rent expense for the six months ended June 30, 2020 and 2019 was $0.4 million and $0.3 million, respectively. Future minimum lease commitments under noncancelable operating leases at June 30, 2020 are presented below:

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NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)


(In thousands)	Commitment
Year
2020 (remainder of)	$	656
2021	1,345
2022	1,419
2023	1,498
2024	1,581
Thereafter	4,445
Total	$	10,944

Contingencies

Brigham Minerals may, from time to time, be a party to certain lawsuits and claims arising in the ordinary course of business. The outcome of such lawsuits and claims cannot be estimated with certainty and management may not be able to estimate the range of possible losses. Brigham Minerals records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Minerals had no reserves for contingencies at June 30, 2020 and December 31, 2019.

14. Related-Party Transactions

Brigham Exploration Company, partially owned by Ben M. Brigham, on occasion leases some of our acreage at market rates. Brigham Minerals did not lease any acreage to Brigham Exploration Company during the three and six months ended June 30, 2020 and therefore did not receive any payment for those periods. We received payments for the three and six months ended June 30, 2019, of $0.2 million and $0.4 million, respectively, from Brigham Exploration Company in connection with such leases.

The Company is party to a services agreement with RS Energy Group, which provides the Company with certain software and services that assist in evaluating the acquisition of mineral interests. Warburg Pincus owned a controlling stake in RS Energy Group until February 2020. The service fees incurred under this agreement were less than $0.1 million for the three and six months ended June 30, 2020 and 2019, respectively.

15. 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 beginning in the first quarter of 2020 and continuing through the second quarter of 2020. The declining commodity prices have 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 2020 and beyond, which has and will adversely affect the near-term development of the Company's properties. Further, these lower commodity prices have resulted in some of the Company's operators shutting in or curtailing production from wells on its properties during the second quarter of 2020 and may cause them to even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions.

In response to the COVID-19 pandemic, the potential risk to Brigham Minerals' workforce and in compliance with stay at home orders, the Company successfully implemented policies and the technological infrastructure for all of its employees to work from home in the first quarter of 2020 and ceased all business travel. In compliance with the requirements for the re-opening of the Texas economy, the Company has re-opened its office at 50% capacity while continuing to support remote working for its employees. Due to these efforts, the Company did not experience material disruptions to its operations or the health of its workforce and has maintained the engagement and connectivity of its personnel.

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16. Subsequent Events

On August 6, 2020, the Board of Directors of Brigham Minerals declared a dividend of $0.14 per share of Class A common stock payable on September 3, 2020, to shareholders of record at the close of business on August 27, 2020.

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

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, 2019 (the “Annual Report”), as well as the accompanying unaudited condensed consolidated and combined financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q (this "Quarterly Report"). In connection with our corporate reorganizations, we became the managing member of Brigham Minerals Holdings, LLC (“Brigham LLC”) and are indirectly responsible for all operational, management and administrative decisions related to Brigham LLC and its operating subsidiaries’ business. In order to furnish comparative financial information, the historical financial information relating to periods prior to our initial public offering, which we completed in April 2019 (the "IPO") in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" has been retrospectively recast to include the combined historical financial information of both Brigham Resources LLC (at historical carrying values) and Brigham Minerals, taking into account state and federal income taxes and liabilities associated with Brigham Minerals. Unless the context otherwise requires, references in this section to the "Company," "we," "us," "our" or like terms, refer to the assets and operations (including reserves, production and acreage) of Brigham Resources LLC, excluding the historical results and operations of Brigham Resources Operating, LLC (which was distributed to our owners prior to the IPO) (“Brigham Operating”) and Brigham Minerals and its subsidiaries.

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 portfolio and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of June 30, 2020, we owned 83,575 net royalty acres across 39 counties within the Permian Basin 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 Operating and Overview:

•Our production volumes increased 31%, to 8,854 Boe/d (71% liquids, 50% oil), for the three months ended June 30, 2020, and increased 58%, to 9,628 Boe/d (72% liquids, 53% oil), for the six months ended June 30, 2020 as compared to the corresponding periods from the prior year.

•Our royalty revenues comprised of crude oil, natural gas and NGL sales decreased 46%, to $12.5 million, for the three months ended June 30, 2020, and increased 1%, to $40.9 million, for the six months ended June 30, 2020 as compared to the corresponding periods from the prior year.

•Our net loss for the three months ended June 30, 2020 and 2019 was $6.8 million and $3.2 million, respectively, and our net income for the six months ended June 30, 2020 and 2019 was $2.0 million and $0.8 million, respectively. Adjusted EBITDA and Adjusted EBITDA ex lease bonus decreased 68%, to $5.9 million, and 65% to $5.8 million, respectively, for the three months ended June 30, 2020 and decreased 3% to $31.0 million, and 10% to $27.1 million, respectively, for the six months ended June 30, 2020 as compared to the corresponding periods from the prior year. Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparable measure calculated and presented in accordance with GAAP, please read "How We Evaluate Our Operations—Adjusted EBITDA and Adjusted EBITDA Ex Lease Bonus."

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•On August 6, 2020, the Board of Directors of Brigham Minerals declared a dividend of 0.14 per share of Class A common stock payable on September 3, 2020 to shareholders of record at the close of business on August 27, 2020.

•As of June 30, 2020, Brigham Minerals had a cash balance of $16.5 million and $135.0 million of undrawn capacity on our revolving credit facility, providing the Company with total liquidity of $151.5 million.

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 beginning in the first quarter of 2020 and continuing through the second quarter of 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 negative price of $(36.98) per barrel that occurred in April 2020. Additionally, in July 2020, OPEC+ agreed to increase production again starting in August 2020. We expect market volatility may continue for the foreseable future. Please see “Risk Factors” for further discussion of these events.

In response to the COVID-19 pandemic, the potential risk to our workforce and in compliance with stay at home orders, we successfully implemented policies and the technological infrastructure for all of our employees to work from home in the first quarter of 2020 and ceased all business travel. In compliance with the requirements for the re-opening of the Texas economy, we have re-opened our office at 50% capacity while continuing to support working from home for our employees. Due to these efforts, we have not experienced material disruptions to our operations or the health of our workforce.

The declining commodity prices have adversely affected the revenues we receive for our royalty interests and could affect our ability to access the capital markets on terms favorable to us. Additionally, in response to the declining commodity prices, many operators on our properties have announced significant reductions in their estimated capital expenditures for 2020 and beyond, which has adversely affected the development of our properties and will continue to affect the development of our properties during the second half of the year. Further, these lower commodity prices have resulted in some of the Company's operators shutting in or curtailing production from wells on our properties during the second quarter of 2020 and may cause them to even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions. In connection therewith, our revenues and cash flows from operations have been negatively impacted and as a result, the dividend amount we are able to pay our stockholders has also been negatively impacted. 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, we have experienced and expect a near-term reduced level of potential acquisition opportunities, which will delay our ability to execute on our growth strategy. 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.

Operational Update

Mineral and Royalty Interest Ownership Update

During the second quarter 2020, the Company closed seven transactions, acquiring 300 net royalty acres (standardized to a 1/8th royalty interest) and deploying $2.3 million in capital primarily to the Midland Basin. As of June 30, 2020, the Company had acquired roughly 83,575 net royalty acres, encompassing 12,907 gross (113.2 net) undeveloped horizontal locations, across 39 counties in what the Company views as the cores of the Permian Basin 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.

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

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	Delaware	Midland	SCOOP	STACK	DJ	Williston	Other	Total
Net Royalty Acres
June 30, 2020	26,550	4,800	11,375	10,700	15,600	7,825	6,725	83,575
March 31, 2020	26,550	4,575	11,375	10,700	15,600	7,825	6,650	83,275

Acres Added (Sold) Q/Q	—	225	—	—	—	—	75	300
% Added (sold) Q/Q	—%	5%	—%	—%	—%	—%	1%	—%

Operating Activity Update

DUC Conversions

The Company saw approximately 222 gross (1.2 net) DUCs converted to production during the second quarter, which represented 25% of its gross DUCs (21% of net) in inventory as of first quarter 2020. Second quarter DUC and PDP conversion waterfalls are summarized in the charts below:

Drilling Activity

During the second quarter 2020, the Company identified 36 gross (0.2 net) wells spud on its mineral position. In 2019 and 2018, respectively, the Company averaged 219 gross (1.4 net) and 135 gross (1.0 net) wells spud per quarter. Brigham’s gross and net wells spud activity over the past ten quarters is summarized in the chart below:

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DUC and Permit Inventory

Given the aforementioned challenges facing the global crude market, the near-term conversion of wells from DUC or permits to proved developed producing may be delayed or deferred relative to historic conversion rates. Brigham's DUC and permit inventory as of June 30, 2020 by basin is outlined in the table below:


	Development Inventory by Basin (1)
	Delaware	Midland	SCOOP	STACK	DJ	Williston	Other	Total
Gross Inventory
DUCs	198	157	69	8	128	138	7	705
Permits	165	119	12	9	214	209	7	735
Net Inventory
DUCs	2.1	0.7	0.4	—	1.1	0.3	—	4.6
Permits	1.3	0.5	0.1	—	2.2	0.4	0.1	4.5

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

Regulatory Update

Muscogee (Creek) Nation Reservation

On July 9, 2020, the U.S. Supreme Court ruled that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Prior to the court’s ruling, the prevailing view was that all reservations within Oklahoma had been disestablished prior to statehood in 1907. Although the court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablished. While we cannot predict which other reservations may be similarly found not to have been disestablished or the full extent to which civil jurisdiction may be affected, the ruling could adversely affect title to our mineral interests, to the extent they are found to be located within reservation areas, and significantly impact laws and regulations to which we and our operators and interests

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are subject in Oklahoma, such as taxation, environmental regulation, and the permitting and siting of energy assets. We will continue to monitor developments concerning the effect of this ruling.

Dakota Access Pipeline ("DAPL")

On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of DAPL’s easement from the U.S. Army Corps of Engineers (the “Corps”) and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On August 5, 2020, the U.S. Court of Appeals for the District of Columbia stayed the court's injunction ordering the shutdown of the pipeline, but did not extend the stay to the vacatur of DAPL's easement. If the legal challenges to DAPL are successful, transportation costs for crude oil will likely increase in the Williston Basin and the operators of our properties in the Williston Basin may choose to shut in wells if they are unable to connect those wells to other pipelines or obtain sufficient capacity on other pipelines at an effective cost, both of which may adversely impact our revenues and future production from our properties in the Williston Basin.

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;

•gross and net well spuds, DUCs, DUC conversions and permits;

•commodity prices; and

•Adjusted EBITDA and Adjusted EBITDA ex lease bonus.

Volumes of Oil, Natural Gas and NGLs Produced

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

Gross and Net Well Spuds, DUCs, DUC Conversions and Permits

In order to track and assess the performance of our assets, we monitor and analyze the number of gross and net well spuds, as well as DUCs on our properties. We also constantly monitor the conversions of our DUC and permit inventories by our various operators across our mineral and royalty interests in an effort to evaluate near-term production trends 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 low 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 $1.42 per MMBtu in June 2020 to a high of $6.24 per MMBtu in January 2018. As of June 30, 2020, the posted price for oil was $39.27 per barrel and the Henry Hub spot market price of natural gas was $1.76 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 pandemics such as COVID-19, production levels, availability of transportation and storage, weather cycles and other factors. For example, the effects of the ongoing COVID-19 pandemic, recent actions by oil-producing countries and a declining availability of hydrocarbon storage has contributed to a significant drop in commodity prices beginning in the first quarter of 2020. 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

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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, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the cost of unevaluated properties (the ceiling limitation). A write-down of the carrying value of the full cost pool 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 limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using the trailing 12-month first day of the month oil and natural gas average prices, as adjusted for basis or location differentials, held constant over the life of the reserves (net wellhead prices). As of June 30, 2020, the prices used in the calculation of the ceiling test were $47.13 per barrel of oil and $2.08 per MMbtu of natural gas. Using these prices, the ceiling limitation exceeded the net book value of oil and natural gas properties by approximately $15.0 million and no write off was necessary. Using the trailing 12-month first day of the month oil and natural gas average prices for the period from September 1, 2019 to August 1, 2020, of $44.49 per barrel of oil and $2.00 per MMbtu of natural gas, the net book value as of June 30, 2020, exceeds the ceiling limitation of oil and natural gas properties by less than $10.0 million, and therefore, a write off entry may be necessary in the third quarter of 2020. This ceiling limitation does not consider drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, changes in proved undeveloped locations and production occurring subsequent to June 30, 2020 that may require revisions to estimates of proved reserves. 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

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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 June 30, 2020 and December 31, 2019. For the three and six months ended June 30, 2019, we recognized a gain of $0.1 million and a loss of $0.6 million on our commodity derivative instruments, respectively. See “Note 6—Derivative Instruments” to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report.

Adjusted EBITDA and Adjusted EBITDA Ex Lease Bonus

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

We define Adjusted EBITDA as net income (loss) before depreciation, depletion and amortization, share-based compensation expense, interest expense, gain or loss on derivative instruments, loss on extinguishment of debt, and income tax expense, less other income and gain or loss on sale of oil and gas properties. We define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus revenue we receive due to the unpredictability of timing and magnitude of the revenue.

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2020		2019		2020		2019
Reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to net income:
Net (loss) income	$	(6,816)	$	(3,207)	$	1,985	$	829
Add:
Depreciation, depletion, and amortization	11,200		6,760		24,026		11,876
Share-based compensation expense	1,853		6,495		3,736		6,495
Interest expense, net	545		1,270		577		5,095
Loss on extinguishment of debt	—		6,933		—		6,933
Loss on derivative instruments, net	—		—		—		612


Income tax expense	—		117		732		307
Less:
Gain on derivative instruments, net	—		73		—		—

Other income, net	23		6		25		35

Income tax benefit	850		—		—		—
Adjusted EBITDA	$	5,909	$	18,289	$	31,031	$	32,112
Less:
Lease bonus revenue	62		1,480		3,968		2,155
Adjusted EBITDA ex lease bonus	$	5,847	$	16,809	$	27,063	$	29,957

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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 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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019

Royalty revenues
Oil sales	78	%	78	%	74	%	77	%
Natural gas sales	12	%	9	%	10	%	11	%
NGL sales	10	%	7	%	7	%	7	%
Total royalty revenue	100	%	94	%	91	%	95	%
Lease bonus revenue	—	%	6	%	9	%	5	%
Total revenues	100	%	100	%	100	%	100	%

Principle Components of Our Cost Structure

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

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 ("CG&A").

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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, audit and other fees for professional services and legal compliance. As a result of becoming a public company, we incurred incremental G&A expenses including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group including share-based compensation, annual and quarterly reports to stockholders, tax return preparation, independent and internal auditor fees, investor relations activities, capital markets activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These incremental G&A expenses are not reflected in our historical financial statements before the IPO date.

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. Our predecessor was treated as a flow-through entity, and is currently treated as a disregarded entity, for U.S. federal income tax purposes and, as such, is generally not subject to U.S. federal income tax at the entity level.

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Results of Operations

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019

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 June 30,
(Dollars in thousands, except for realized prices and unit expenses)	2020		2019		Variance
Production:
Oil (MBbls)	404		346		58		17	%
Natural gas (MMcf)	1,402		1,066		336		32	%
NGLs (MBbls)	168		92		76		83	%
Equivalents (MBoe)	806		616		190		31	%
Equivalents per day (Boe/d)	8,854		6,768		2,086		31	%
Revenues:
Oil sales	$	9,766	$	19,140	$	(9,374)	(49)	%
Natural gas sales	1,555		2,309		(754)		(33)	%
NGL sales	1,222		1,600		(378)		(24)	%
Total mineral and royalty revenue	$	12,543	$	23,049	$	(10,506)	(46)	%
Lease bonus and other revenue	62		1,480		(1,418)		(96)	%
Total revenues	$	12,605	$	24,529	$	(11,924)	(49)	%
Realized prices, without derivatives:
Oil ($/Bbl)	$	24.15	$	55.24	$	(31.09)	(56)	%
Natural gas ($/Mcf)	1.11		2.17		(1.06)		(49)	%
NGLs ($/Bbl)	7.28		17.42		(10.14)		(58)	%
Equivalents ($/Boe)	$	15.57	$	37.42	$	(21.85)	(58)	%
Realized prices, with derivatives:
Oil ($/Bbl) (1)	$	24.15	$	55.36	$	(31.21)	(56)	%
Equivalents ($/Boe) (1)	15.57		37.49		(21.92)		(58)	%
Operating expenses:
Gathering, transportation and marketing	$	1,625	$	1,523	$	102	7	%
Severance and ad valorem taxes	1,034		1,450		(416)		(29)	%
Depreciation, depletion, and amortization	11,200		6,760		4,440		66	%
General and administrative (before share-based compensation)	4,037		3,267		770		24	%
Total operating expenses (before share-based compensation)	$	17,896	$	13,000	$	4,896	38	%
Share-based compensation	1,853		6,495		(4,642)		(71)	%
Total operating expenses	$	19,749	$	19,495	$	254	1	%
Other expenses:
Interest expense, net	$	545	$	1,270	$	(725)	(57)	%
Loss on extinguishment of debt	—		6,933		(6,933)		(100)	%
(Gain) loss on derivative instruments, net	—		(73)		73		(100)	%
Total other expenses	$	545	$	8,130	$	(7,585)	(54)	%

(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

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	Three Months Ended June 30,
Unit Expenses ($/Boe)	2020		2019		Variance
Gathering, transportation and marketing	$	2.02	$	2.47	$	(0.45)	(18)	%
Severance and ad valorem taxes	1.28		2.35		(1.07)		(46)	%
Depreciation, depletion and amortization	13.90		10.98		2.92		27	%
General and administrative (before share-based compensation)	5.01		5.30		(0.29)		(5)	%
General and administrative, share-based compensation	2.30		10.55		(8.25)		(78)	%
Interest expense, net	0.68		2.06		(1.38)		(67)	%

Revenues

Total revenues for the three months ended June 30, 2020 decreased 49%, or $11.9 million, compared to the three months ended June 30, 2019. The decrease was attributable to a $10.5 million decrease in mineral and royalty revenues and a $1.4 million decrease in lease bonus revenues during the period. The decrease in mineral and royalty revenue was primarily attributable to the 58% decrease in realized commodity prices, resulting in a decrease in royalty revenues of $17.6 million. This was partially offset by a 31% increase in production volumes to 8,854 Boe/d, resulting in an increase in revenues of $7.1 million, which was primarily attributable to the drilling and completion activity on our mineral and royalty interests.

Oil revenues for the three months ended June 30, 2020 decreased 49%, or $9.4 million, compared to the three months ended June 30, 2019. The decrease in oil revenues was primarily attributable to the 56% decrease in realized oil prices to $24.15 per barrel, resulting in a decrease in revenues of $12.6 million. This was partially offset by a 17% increase in oil production volumes to 4,443 barrels per day, resulting in a $3.2 million increase in oil revenues. The increase in oil production volumes for the period was primarily attributable to the drilling and completion activity on our properties in the Permian Basin. In particular, production volumes in the Permian Basin increased 72% compared to the corresponding period from the prior year.

Natural gas revenues for the three months ended June 30, 2020 decreased 33%, or $0.8 million, compared to the three months ended June 30, 2019. The decrease in natural gas revenues was primarily attributable to the 49% decrease in realized natural gas prices to $1.11 per Mcf, resulting in a decrease in revenues of $1.5 million. This was partially offset by a 32% increase in natural gas production volumes to 15,407 Mcf/d, resulting in a $0.7 million increase in natural gas revenues. The increase in natural gas production volumes for the period was primarily attributable to ongoing drilling and completion activity on our properties in the Anadarko and Permian Basins.

NGL revenues for the three months ended June 30, 2020 decreased 24%, or $0.4 million, compared to the three months ended June 30, 2019. The decrease in NGL revenues was primarily attributable to the 58% decrease in realized NGL prices to $7.28 per barrel, resulting in a decrease of $1.7 million in NGL revenues. This was partially offset by a 83% increase in NGL volumes to 1,843 barrels per day, resulting in an increase in revenues of $1.3 million. The increase in NGL production volumes was largely attributable to the ongoing drilling and completion activity on our properties in the Permian and Anadarko Basins.

Lease Bonus 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 June 30, 2020 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 June 30, 2020, GTM expenses increased 7%, or $0.1 million, compared to the three months ended June 30, 2019, primarily due to the increase in production volumes.

Severance and ad valorem taxes. For the three months ended June 30, 2020, severance and ad valorem taxes decreased 29%, or $0.4 million, over the three months ended June 30, 2019, primarily due to the decrease in royalty revenues.

Depreciation, depletion and amortization. DD&A expense increased 66%, or $4.4 million, for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019. Higher production volumes increased our depletion expense by

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$2.0 million and a higher depletion rate increased our depletion expense by $2.4 million. The depletion rate was $13.74 per Boe and $10.74 per Boe for the three months ended June 30, 2020 and 2019, respectively. The increase in the depletion rate was a result of recent acquisition efforts focused on largely de-risked acreage with an increased likelihood of near-term production and development, as well as reclassification of proved undeveloped reserves to probable and possible reserves due to changes in the development timing largely in the Anadarko Basin. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.

General and administrative and share-based compensation. General and administrative expense (before share-based compensation) increased 24%, or $0.8 million, for the three months ended June 30, 2020, compared to the three months ended June 30, 2019 primarily due to $0.5 million in incremental legal, professional, audit, and tax fees as a result of the Company's June 2020 Secondary Offering and $0.3 million in incremental fees associated with our first proxy filing and various stock exchange fees that were not incurred during the second quarter of 2019.

Share-based compensation expense for the three months ended June 30, 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 capitalized to evaluated property. Share-based compensation expense for the three months ended June 30, 2019 was $6.5 million, net of $1.0 million of share-based compensation cost capitalized to unevaluated property. At IPO, we recognized $2.0 million of share-based compensation cost related to the restricted incentive units granted in April 2013 and September 2015 and 2018 ("Incentive Units"). Additionally, in April 2019, in connection with the IPO, we adopted the Brigham Minerals, Inc. 2019 Long-Term Incentive Plan (“LTIP”) and granted restricted share awards (“RSAs”), time-based restricted share units (“RSUs”) and performance-based restricted share units (“PSUs”) to our employees and executives. Certain of the RSAs vested immediately and we recognized $3.2 million of share-based compensation cost related to the RSAs. Also, subsequent to the IPO and prior to June 30, 2019, we recognized an additional $2.3 million of share-based compensation cost related to the Incentive Units and the awards granted under the LTIP. No share-based compensation expenses were recognized prior to the IPO because the IPO was not considered probable. See "Note 11—Share-Based Compensation" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

Interest expense, net. Interest expense decreased $0.7 million for the three months ended June 30, 2020 compared to the three months ended June 30, 2019. Interest expense for the three months ended June 30, 2020 consisted of $0.4 million of amortized debt issuance cost, of which $0.3 million is related to the accelerated amortization of debt issuance costs associated with the reduction in our borrowing base from $180.0 million to $135.0 million, and $0.2 million of loan commitment fees. For the three months ended June 30, 2019, our weighted average debt outstanding on our Owl Rock credit facility was $79.0 million with a weighted average interest rate of 7.9%. In May 2019, a portion of the net proceeds received from the IPO were used to fully repay the outstanding borrowings under the Owl Rock credit facility. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further details.

Loss on extinguishment of debt. As a result of the full repayment of the outstanding balance of the Owl Rock credit facility of $200.0 million in May 2019, we recognized a loss on extinguishment of debt of approximately $6.9 million for the three months ended June 30, 2019. The loss on extinguishment of debt consisted of a $4.0 million write-off of capitalized debt issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion of this transaction.

Gain on derivative instruments, net. Brigham Minerals' existing oil derivative contracts expired as of December 31, 2019. For the three months ended June 30, 2019, the Company recognized a net gain on oil derivative instruments of $0.1 million. See "Note 6—Derivative Instruments" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

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Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

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:


	Six Months Ended June 30,
(Dollars in thousands, except for realized prices and unit expenses)	2020		2019		Variance
Production:
Oil (MBbls)	921		613		308		50	%
Natural gas (MMcf)	2,986		1,935		1,051		54	%
NGLs (MBbls)	333		165		168		102	%
Equivalents (MBoe)	1,752		1,100		652		59	%
Equivalents per day (Boe/d)	9,628		6,079		3,549		58	%
Revenues:
Oil sales	$	33,353	$	32,715	$	638	2	%
Natural gas sales	4,346		4,896		(550)		(11)	%
NGL sales	3,218		3,028		190		6	%
Total mineral and royalty revenue	$	40,917	$	40,639	$	278	1	%
Lease bonus and other revenue	3,968		2,155		1,813		84	%
Total revenues	$	44,885	$	42,794	$	2,091	5	%
Realized prices, without derivatives:
Oil ($/Bbl)	$	36.20	$	53.34	$	(17.14)	(32)	%
Natural gas ($/Mcf)	1.46		2.53		(1.07)		(42)	%
NGLs ($/Bbl)	9.66		18.41		(8.75)		(48)	%
Equivalents ($/Boe)	$	23.35	$	36.93	$	(13.58)	(37)	%
Realized prices, with derivatives:
Oil ($/Bbl) (1)	$	36.20	$	53.73	$	(17.53)	(33)	%
Equivalents ($/Boe) (1)	23.35		37.15		(13.80)		(37)	%
Operating expenses:
Gathering, transportation and marketing	$	3,404	$	2,637	$	767	29	%
Severance and ad valorem taxes	2,786		2,829		(43)		(2)	%
Depreciation, depletion, and amortization	24,026		11,876		12,150		102	%
General and administrative (before share-based compensation)	7,664		5,216		2,448		47	%
Total operating expenses (before share-based compensation)	$	37,880	$	22,558	$	15,322	68	%
Share-based compensation	3,736		6,495		(2,759)		(42)	%
Total operating expenses	$	41,616	$	29,053	$	12,563	43	%
Other expenses:
Interest expense, net	$	577	$	5,095	$	(4,518)	(89)	%
Loss on extinguishment of debt	—		6,933		(6,933)		(100)	%
Loss on derivative instruments, net	—		612		(612)		(100)	%
Total other expenses	$	577	$	12,640	$	(12,063)	(95)	%

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	Six Months Ended June 30,
Unit Expenses ($/Boe)	2020		2019		Variance
Gathering, transportation and marketing	$	1.94	$	2.40	$	(0.46)	(19)	%
Severance and ad valorem taxes	1.59		2.57		(0.98)		(38)	%
Depreciation, depletion and amortization	13.71		10.79		2.92		27	%
General and administrative (before share-based compensation)	4.37		4.74		(0.37)		(8)	%
General and administrative, share-based compensation	2.13		5.90		(3.77)		(64)	%
Interest expense, net	0.33		4.63		(4.30)		(93)	%

Revenues

Total revenues for the six months ended June 30, 2020 increased 5%, or $2.1 million, compared to the six months ended June 30, 2019. The increase was attributable to a $0.3 million increase in mineral and royalty revenues during the period and a $1.8 million increase in lease bonus revenues. The increase in mineral and royalty revenue was primarily attributable to increased drilling and completion activity on our mineral and royalty interests, which resulted in a 58% increase in production volumes to 9,628 Boe/d and a corresponding increase in revenues of $24.1 million. This was mostly offset by a 37% decrease in realized commodity prices, resulting in a decrease in royalty revenues of $23.8 million.

Oil revenues for the six months ended June 30, 2020 increased 2%, or $0.6 million, compared to the six months ended June 30, 2019. Oil production volumes increased 50% to 5,063 barrels per day, resulting in a $16.4 million increase in oil revenues. The increase in oil production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin. In particular, production volumes in the Permian Basin for the six months ended June 30, 2020 were up 113%, compared to the six months ended June 30, 2019. This was mostly offset by a 32% decrease in realized oil prices to $36.20 per barrel, resulting in a decrease in revenues of $15.8 million.

Natural gas revenues for the six months ended June 30, 2020 decreased 11%, or $0.6 million, compared to the six months ended June 30, 2019. The decrease in natural gas revenues was primarily attributable to a 42% decrease in realized natural gas prices to $1.46 per Mcf, resulting in a decrease in revenues of $3.2 million. This was partially offset by a 54% increase in natural gas production volumes to 16,409 Mcf/d, resulting in a $2.6 million increase in natural gas revenues. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin.

NGL revenues for the six months ended June 30, 2020 increased 6%, or $0.2 million, compared to the six months ended June 30, 2019. NGL production volumes increased 102% to 1,830 barrels per day, resulting in an increase in NGL revenues of $3.1 million. The increase in NGL production volumes was largely attributable to the increase in drilling and completion activity on our properties in the Permian Basin. This was partially offset by a 48% decrease in realized NGL prices to $9.66 per barrel, resulting in a decrease of $2.9 million in NGL revenues.

Lease Bonus 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 six months ended June 30, 2020 is primarily attributable to the highly variable nature of leasing activity from period to period. 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 six months ended June 30, 2020, GTM expense increased 29%, or $0.8 million compared to the six months ended June 30, 2019, primarily due to the higher production volumes.

Severance and ad valorem taxes. For the six months ended June 30, 2020, severance and ad valorem taxes decreased 2%, compared to the six months ended June 30, 2019, consistent with the relatively flat revenues over the periods.

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Depreciation, depletion and amortization. DD&A expense increased 102%, or $12.2 million, for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. Higher production volumes increased our DD&A expense by $6.9 million and a higher depletion rate increased our DD&A expense by $4.9 million. The depletion rate was $13.31 per Boe and $10.53 per Boe for the six months ended June 30, 2020 and 2019, respectively. The increase in the depletion rate was a result of recent acquisition efforts focused on largely de-risked acreage with an increased likelihood of near-term production and development, as well as reclassification of proved undeveloped reserves to probable and possible reserves due to changes in the development timing largely in the Anadarko Basin. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.

General and administrative and share-based compensation. General and administrative expenses (before share-based compensation) increased 47%, or $2.4 million, for the six months ended June 30, 2020, compared to the six months ended June 30, 2019. Increases to G&A expenses are a result of: (i) $0.7 million incremental D&O insurance expense and Board of Director fees; (ii) $0.5 million in incremental legal, professional, audit, and tax fees as a result of the Company's June 2020 Secondary Offering; (iii) $0.3 million in incremental fees associated with our first proxy filing and various stock exchange fees that were not incurred during the six months ended June 30, 2019 ; (iv) $0.3 million of additional rent and payroll expense; (v) $0.2 million in Delaware franchise taxes; and (vi) $0.4 million in additional legal, audit, and other services.

Share-based compensation expense for the six months ended June 30, 2020 was $3.7 million, net of $1.8 million of share-based compensation cost capitalized to unevaluated property and $1.2 million of share-based compensation cost capitalized to evaluated property. Share-based compensation expense for the six months ended June 30, 2019 was $6.5 million, net of $1.0 million of share-based compensation cost capitalized to unevaluated property. At IPO, we recognized $2.0 million of share-based compensation cost related to the Incentive Units. Additionally, in April of 2019, in connection with the IPO, we adopted the LTIP and granted RSAs, RSUs, and PSUs to our employees and executives. Certain of the RSAs vested immediately and we recognized $3.2 million of share-based compensation cost related to the RSAs. Also, subsequent to the IPO and prior to June 30, 2019, we recognized an additional $2.3 million of share-based compensation cost related to the Incentive Units and the awards granted under the LTIP. No share-based compensation expenses were recognized prior to the IPO because the IPO was not considered probable. See "Note 11—Share-Based Compensation" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

Interest expense, net. Interest expense decreased $4.5 million for the six months ended June 30, 2020 compared to the six months ended June 30, 2019. For the six months ended June 30, 2020, we had no outstanding debt on our credit facility. The interest expense for the six months ended June 30, 2020 consisted of $0.5 million of amortized debt issuance cost, of which $0.3 million is related to the accelerated amortization of debt issuance costs associated with the reduction in our borrowing base from $180.0 million to $135.0 million, and $0.4 million of loan commitment fees. This was partially offset by interest income of $0.3 million. For the six months ended June 30, 2019, our weighted average debt outstanding on our Owl Rock credit facility was $129.3 million with a weighted-average interest rate of 7.9%. In May 2019, a portion of the net proceeds received from the IPO were used to fully repay the outstanding borrowings under the Owl Rock credit facility. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further details.

Loss on extinguishment of debt. As a result of the full repayment of the outstanding balance of the Owl Rock credit facility of $200.0 million in May 2019, we recognized a loss on extinguishment of debt of approximately $6.9 million for the six months ended June 30, 2019. The loss on extinguishment of debt consisted of a $4.0 million write-off of capitalized debt issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion of these transactions.

Loss on derivative instruments, net. Brigham Minerals' existing oil derivative contracts expired on December 31, 2019. For the six months ended June 30, 2019, we recognized a net loss on derivative instruments of $0.6 million. See "Note 6—Derivative Instruments" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor

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

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Corporate Reorganization

The historical unaudited condensed consolidated and combined financial statements included in this Quarterly Report for periods on or before April 23, 2019 are based on the financial statements of our predecessor and Brigham Minerals prior to our corporate reorganization consummated in connection with our IPO. As a result, such historical condensed consolidated and combined financial data may not give you an accurate indication of what our actual results would have been if the corporate reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Brigham Minerals acquired an indirect interest in Brigham Resources on July 16, 2018 in a series of restructuring transactions pursuant to which certain entities affiliated with Warburg Pincus LLC ("Warburg Pincus") contributed all of their respective interests in the entities through which they held interests in Brigham Resources to Brigham Minerals in exchange for all of the outstanding shares of common stock of Brigham Minerals (the “July 2018 restructuring”). As a result of such restructuring transactions, Brigham Minerals became wholly owned by an entity affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a 16.5% membership interest in Brigham Resources. The remaining outstanding membership interests of Brigham Resources remained with the Original Owners.

On November 20, 2018, Brigham Resources underwent a second series of restructuring transactions that are collectively referred to in this Quarterly Report as the “November 2018 Restructuring.” In connection with the November 2018 Restructuring, Brigham Resources became a wholly owned subsidiary of Brigham LLC. In April 2019, Brigham Minerals completed the IPO of 16,675,000 shares of Class A common stock at a price to the public of $18.00 per share. As a result of the IPO, Brigham Minerals became a holding company whose sole material asset consisted of a 43.3% interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly-owned subsidiary, Brigham Resources.

The corporate reorganization that was completed contemporaneously with the closing of the IPO provided a mechanism by which the Brigham LLC Units to be allocated amongst the Original Owners, including the holders of our management incentive units, was determined. As a result of the IPO, the satisfaction of all conditions relating to the vesting of certain management incentive units held in Brigham Equity Holdings, LLC (“Brigham Equity Holdings”) by our management and employees became probable. Accordingly, at the IPO, we recognized a cumulative effect adjustment to share-based compensation cost of approximately $2.0 million pertaining to the period from the grant date through the IPO date, related to the estimated fair value of the Incentive Units at grant, all of which was non-cash. No share-based compensation expenses were recognized prior to the IPO because the IPO was not considered probable. During the six months ended June 30, 2020, we recognized $3.7 million in non-cash, share-based compensation expense related to the Incentive Units, RSAs, RSUs, and PSUs, net of capitalized share-based cost of $3.0 million.

Public Company Expenses

As a result of the IPO, we incur direct, incremental G&A expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive

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with our public company peer group, including share-based compensation, preparing annual and quarterly reports to stockholders, tax return preparation, independent and internal auditor fees, investor relations activities, capital markets activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in our results of operations prior to the IPO.

Income Taxes

Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor was treated as a flow-through entity, and is currently treated as a disregarded entity, for U.S. federal income tax purposes and, as such, is generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income is passed through to its members, including Brigham Minerals. Accordingly, the financial data of our predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas).

Capital Requirements and Sources of Liquidity

Prior to our IPO, our primary sources of liquidity were capital contributions from our Original Owners, borrowings under our debt arrangements and cash flows from operations. Subsequent to our IPO, our current primary sources of liquidity are cash flows from operations, 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, coupled with many of our operators announcing significant reductions in projected capital expenditures for 2020 and beyond, our revenues and cash flows from operations have been and will continue to be negatively impacted for the remainder of 2020 and we may not have access to capital markets on terms favorable to us or at all.

Our primary uses of capital are for the payment of dividends to our stockholders and for investing in our business, specifically the acquisition of additional mineral and royalty interests. In connection with the ongoing COVID-19 pandemic, our cash flows from operations have been and will continue to be negatively impacted, and as a result, the dividend amount we are able to pay our stockholders 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 six months ended June 30, 2020, we incurred approximately $31.7 million for acquisition-related capital expenditures, inclusive of a $3.0 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. In connection with the previously mentioned COVID-19 pandemic, we have experienced and expect a near-term reduced level of potential acquisition opportunities, which will delay our ability to execute on our growth strategy. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy. 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 June 30, 2020, the borrowing base under our revolving credit facility was $135.0 million, and we had no outstanding borrowings. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion of this transaction. As of June 30, 2020, we had liquidity of $151.5 million.

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $28.6 million at June 30, 2020, as compared to $71.6 million at December 31, 2019. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.

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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 $16.5 million and $51.1 million at June 30, 2020 and December 31, 2019, respectively. The decrease in cash and cash equivalents was primarily due to acquisitions made and payment of dividends to our stockholders during the six months ended June 30, 2020. See "Note 4—Acquisitions and Divestitures" to the condensed consolidated and combined 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.

Cash Flows

The following table summarizes our cash flows for the periods indicated:


	Six Months Ended June 30,
(In thousands)	2020		2019
Net cash provided by operating activities	$	38,617	$	29,567
Net cash used in investing activities (1)	(27,476)		(79,165)
Net cash (used in) provided by financing activities	(45,809)		100,307

(1) The net cash used in investing activities for the six months ended June 30, 2019 was adjusted as a result of our adoption of ASU 2016-18, Statement of Cash Flow. See "Note 2—Summary of Significant Accounting Policies—Restricted Cash" to the condensed consolidated and combined financials statements of Brigham Minerals included elsewhere in this Quarterly Report for further discussion.

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019

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 revenue and changes in working capital. The increase in net cash provided by operating activities for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 is primarily due to a 58% increase in production volumes and higher lease bonus revenues partially offset by the 37% decrease in realized prices during the six months ended June 30, 2020 and the increases in operating expenses during such period discussed above.

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 six months ended June 30, 2020, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $28.8 million, offset by sales of mineral and royalty interests totaling $1.6 million. For the six months ended June 30, 2019, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests of $81.1 million, offset by sales of mineral and royalty interests totaling $2.0 million.

Net cash used in financing activities

Net cash used in financing activities for the six months ended June 30, 2020 was primarily due to the dividends paid to holders of our Class A common stock of $25.8 million and distributions to holders of temporary equity of $19.8 million. Net cash provided by financing activities for the six months ended June 30, 2019 was primarily related to $278.5 million in net proceeds received from the Offering and borrowings under our Owl Rock credit facility of $25.0 million, offset by $200.0 million used to fully repay borrowings under our Owl Rock credit facility.

Our Owl Rock Credit Facility

On July 27, 2018, we entered into a credit agreement with Owl Rock Capital Corporation, as administrative agent and collateral agent (our "Owl Rock credit facility"). Our Owl Rock credit facility was subject to customary fees, guarantees of subsidiaries, restrictions and covenants, including certain restricted payments, and was collateralized by certain of our royalty and mineral properties.

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Our Owl Rock credit facility provided for a $125.0 million initial term loan and a $75.0 million delayed draw term loan (“DDTL”). Also, a $10.0 million revolving credit facility was available for general corporate purposes, which was undrawn as of May 7, 2019. In addition, as of May 7, 2019, we had $200.0 million of term loans and DDTL borrowings outstanding under our Owl Rock credit facility. We used a portion of the proceeds from the IPO to fully repay the outstanding borrowings under the term loan portion and DDTL portion of our Owl Rock credit facility and terminated the Owl Rock credit facility on May 7, 2019. Our Owl Rock credit facility bore interest at a rate per annum equal to, at our option, (a) the base rate plus 4.50%, or (b) the adjusted LIBOR rate for such interest period (subject to a 1.00% floor) plus 5.50%. Our Owl Rock credit facility required us to maintain compliance with customary financial and collateral coverage ratios. See "Note 8—Long-Term Debt" to the condensed consolidated and combined financial statements of Brigham Minerals contained elsewhere in this Quarterly Report for further discussion.

Revolving Credit Facility

On May 16, 2019, Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as 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. As of June 30, 2020, the borrowing base was $135.0 million and we had no outstanding balance on our revolving credit facility.

Contractual Obligations

A summary of our contractual obligations as of June 30, 2020, is provided in the following table.


	By Year:
(In thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Office lease	$	656	$	1,345	$	1,419	$	1,498	$	1,581	$	4,445	$	10,944

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Off-Balance Sheet Arrangements

As of June 30, 2020, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

As of June 30, 2020, 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 negative price of $(36.98) per barrel in April 2020 to a high of $77.41 per barrel in June 2018, and as of June 30, 2020, the posted price for oil was $39.27 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 $1.42 per MMBtu in June 2020 to a high of $6.24 per MMBtu in January 2018, and as of June 30, 2020, the Henry Hub spot market price of natural gas was $1.76 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 discussed in this Quarterly Report under “Item 1A—Risk Factors—Risks Related to Our Business—Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. The significant drop in the price of oil in the first half of 2020 has adversely affected, and any further decline in commodity prices in the future may adversely affect, our business, financial condition or results of operations.”

A $1.00 per barrel change in our realized oil price would have resulted in a $0.9 million change in our oil revenues for the six months ended June 30, 2020. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million change in our natural gas revenues for the six months ended June 30, 2020. A $1.00 per barrel change in NGL prices would have resulted in a $0.3 million change in our NGL revenues for the six months ended June 30, 2020. Total revenues for the six months ended June 30, 2020 was comprised of 74% from oil sales, 10% from natural gas sales, and 7% 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 as of June 30, 2020 and 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.

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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. See "Item 1A—Risk Factors—We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties."

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. As of June 30, 2020, we had no outstanding balance on our revolving credit facility.

Item 4. — Controls and Procedures

Internal Controls Over Financial Reporting

Upon becoming a public company, we became required to comply with the SEC’s rules implementing Section 302 and Section 404 of the Sarbanes-Oxley Act, which requires our management to certify financial and other information in our quarterly and annual reports, and, beginning with the year following the first fiscal year for which we are required to file an annual report with the SEC, provide an annual management report on the effectiveness of our internal control over financial reporting. In addition, we will be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 beginning with our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

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 June 30, 2020. 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 June 30, 2020.

Change in Internal Controls Over Financial Reporting

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the period covered by this Quarterly Report on Form 10-Q that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. We have not experienced any material impact to our internal controls over financial reporting despite the fact that some of our employees are working remotely in compliance with the current Texas requirements due to the COVID-19 pandemic. We are continually monitoring and assessing the effects of the COVID-19 situation on our internal controls to minimize the impact on their design and operating effectiveness.

PART II — OTHER INFORMATION

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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 below and also under the caption “Risk Factors” in our Annual Report. Except for the additional risk factors and updates set forth below, there have been no material changes in our risk factors from those previously disclosed under “Risk Factors” in our Annual Report.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the continuing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a disruption to the oil and natural gas industry and to our business. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Furthermore, the COVID-19 pandemic has affected our operations by (i) rendering our personnel unable to access company facilities for an extended period of time, (ii) contributing to a steep decline in commodities prices in the first half of 2020, which has reduced activity by our operators and the amounts of royalty payments we receive, (iii) causing some of the Company’s operators to shut in and curtail production from wells on the Company’s properties, (iv) limiting our access to the capital markets on terms favorable to us and adversely affected our capital resources and (v) reducing the level of potential acquisition opportunities we have been able to identify, limiting our ability to execute on our growth strategy of acquiring additional mineral and royalty interests. Additionally, the steps taken by national, state and local governments to curb the spread of the COVID-19 pandemic, including stay-at-home orders, quarantines, travel restrictions and business shutdowns, and the implications on our operators’ workforce of a COVID-19 infection, have limited our operators’ ability to maintain production from our properties. Such orders and the other impacts of the COVID-19 pandemic may have limited the ability of our operators to access our properties and maintain their existing production and development activities, and any similar or more restrictive measures taken in the future could have similar effects.

While our business and operations have experienced certain effects of the COVID-19 pandemic as described above, the full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to operating production activities by our operators and the impact of potential governmental restrictions on travel, transportation and operations. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. The significant drop in the price of oil in the first half of 2020 has adversely affected, and any further decline in commodity prices in the future may adversely affect, our business, financial condition or results of operations.

Our revenues, operating results, free cash flow and the carrying value of our mineral and royalty interests depend significantly upon the quantities of oil, natural gas and NGLs produced from our properties and the prevailing prices at which such production is sold. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

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•the domestic and foreign supply of and demand for oil, natural gas and NGLs;

•market expectations about future prices of oil, natural gas and NGLs;

•the level of global oil, natural gas and NGL exploration and production;

•the cost of exploring for, developing, producing and delivering oil, natural gas and NGLs;

•the price and quantity of foreign imports and U.S. exports of oil, natural gas and NGLs;

•the level of U.S. domestic production;

•the availability of storage for hydrocarbons;

•political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;

•the ability of members of the Organization of Petroleum Exporting Countries (“OPEC”) and other countries that produce oil, natural gas and NGLs to agree to and maintain oil price and production controls;

•trading in oil, natural gas and NGL derivative contracts;

•the level of consumer product demand;

•weather conditions and natural disasters;

•technological advances affecting energy consumption, energy storage and energy supply;

•domestic and foreign governmental regulations and taxes;

•the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran;

•global or national health concerns, including health epidemics such as the ongoing COVID-19 pandemic beginning in the first quarter of 2020;

•the proximity, cost, availability and capacity of oil, natural gas and NGL pipelines and other transportation facilities;

•the price and availability of alternative fuels; and

•overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, during the past five years, the posted price for West Texas Intermediate (“WTI”) light sweet crude oil has ranged from a historic low negative price of $(36.98) per barrel in April 2020 to a high of $77.41 per barrel in June 2018, and the Henry Hub spot market price of natural gas has ranged from a low of $1.42 per MMBtu in June 2020 to a high of $6.24 per MMBtu in January 2018. Furthermore, 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+ subsequently agreed to collectively decrease production, these events, combined with the impact of the continued outbreak of the COVID-19 pandemic, have contributed to a significant decrease in prices for oil in the first half of 2020. The effect of these events on the price of oil was further exacerbated by a shortage in available storage for hydrocarbons in the U.S., which caused the prices for oil to further decrease dramatically in April 2020. While the prices for oil have begun to stabilize, such prices have remained materially lower than pre-pandemic levels, which has adversely affected the prices at which production from our properties is sold as well as the production activities of operators on our properties and may continue to do so in the future. This, in turn, has and will materially affect the amount of royalty payments that we receive from such operators.

Any further decline in the price of oil, natural gas and NGLs or a prolonged period of low commodity prices will also materially adversely affect our business, financial condition, results of operations and free cash flow.

In addition, the quantities of oil, natural gas and NGLs produced from our properties has a significant impact on our operating results and financial condition. Lower oil, natural gas and NGL prices may reduce the amount of oil, natural gas and NGLs that can be produced economically by our operators, which may reduce our operators’ willingness to develop and/or continue to produce our properties. For example, partially due to the decrease in prices for oil in the first half of 2020, many operators on our properties have announced significant reductions in their estimated capital expenditures for 2020 and beyond. Further, these lower commodity prices have resulted in some of the Company's operators shutting in or curtailing production from wells on its properties during the second quarter of 2020 and may cause them to even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions. Specifically, operators may abandon any well if they reasonably believe that the well can no longer produce oil, natural gas or NGLs in commercially paying

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quantities. In addition, as a result of the current oversupply of oil globally and current depressed commodity price environment, there have been some discussions at the national and state levels of imposing additional regulatory limits on production volumes. For example, some state oil and gas commissions, including the Oklahoma Corporation Commission, have imposed or are considering imposing oil and gas production limits. To the extent adopted, such production limits could adversely impact the production attributable to our interests, and it is not clear whether they would result in a stabilization or improvement of commodity prices. Separately, several state oil and gas commissions, including the Oklahoma Corporation Commission and the North Dakota Industrial Commission, have allowed or are considering allowing oil producers to curtail production from or shut-in wells to prevent economic waste. Such economic waste determinations could allow producers to maintain leases even if they stop production, which could adversely impact the production attributable to our interests.

The deterioration in commodity prices, decrease in production levels, or further reduction in operator production activities may result in our having to make substantial downward adjustments to our estimated proved, probable or possible reserves. If this occurs or if production estimates change or exploration or development results deteriorate, the full cost method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. In addition, the borrowing base under our revolving credit facility is determined based on our estimated reserves, and any negative revisions to our estimated reserves would in turn reduce our borrowing base, reducing the amount available to fund our operations through borrowings under our revolving credit facility.

We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in the first half of 2020, many of our operators have announced significant reductions in projected capital expenditures for 2020 and beyond. The number of new wells drilled in many of our focus areas has decreased, and such slower development pace may continue in the future.

Our assets consist of mineral and royalty interests. Because we depend on third-party operators for all of the exploration, development and production on our properties, we have little to no control over the operations related to our properties. For the quarter ended June 30, 2020, we received revenues from over 150 operators with approximately 64% of our royalty revenues coming from the top ten operators on our properties, three of which each accounted for more than 10% of such royalty revenues. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Furthermore, in response to the significant decrease in prices for oil in the first half of 2020, many of our operators have announced substantial reductions in their estimated capital expenditures, rig count and completion crews for 2020 and beyond. Our operators may further reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact revenues we receive. The number of new wells drilled in many of our focus areas has decreased, and such slower development pace may continue in the future, especially as a consequence of the reductions in operators’ capital expenditures. Moreover, over the last year, many of our operators have announced that they plan to drill fewer wells per section than previously anticipated, due in part to greater well-interference between parent and child wells than previously anticipated and an increased focus on overall field economics in a low commodity price environment.

If production on our mineral and royalty interests decreases due to decreased development activities, as a result of the low commodity price environment, limited availability of development capital, production-related difficulties or otherwise, our results of operations may be adversely affected. For example, the amount of royalty payments we have received from our operators recently has decreased and will likely continue to decrease due to the lower prices at which our operators are able to sell production from our properties and reduced production activities by our operators. Further, depressed commodity prices have caused some of our operators to voluntarily shut in and curtail production from wells on our properties. An extended period of depressed commodity prices may cause additional operators to take similar action or even to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions, both of which would decrease the amount of royalty payments we receive from our operators. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that are largely outside of our control, including:

•the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;

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•the ability of our operators to access capital;

•prevailing commodity prices;

•the operators' expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

•the availability of storage for hydrocarbons;

•the operators’ expertise, operating efficiency and financial resources;

•approval of other participants in drilling wells;

•the selection of technology;

•the selection of counterparties for the marketing and sale of production; and

•the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and free cash flow. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and free cash flow. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on our cash flows.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. For example, certain of our operators have recently commenced bankruptcy proceeding under the Bankruptcy Code and their future operations and ability to make royalty payments to us may be adversely affected by such proceedings. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced. Additionally, in the current low commodity price environment, some operators have attempted to make improper deductions by netting negative gas price realizations against positive oil royalties and other operators may attempt to do so in the future. We have taken action and will continue to take action to protect our rights; however, we cannot predict whether we will ultimately be successful.

Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions, cash generated by operations, proceeds from our IPO and from the December 2019 Offering and borrowings under our debt arrangements.

In the future, we may need capital in excess of the amounts we retain in our business or borrow under our revolving credit facility. The level of borrowings available under our revolving credit facility is largely based on our estimated reserves and our lenders' price decks, which estimates will be reduced to the extent commodity prices decrease or remain depressed. Accordingly, our ability to access capital under our revolving credit facility has been adversely affected by the significant decrease in commodity prices in the first half of 2020. Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. For example, given the recent significant decline in prices for oil and the broader economic turmoil, our ability to secure financing in the capital markets on terms favorable to us has been adversely impacted. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and free cash flow.

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Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.

Our estimated reserves are based on many assumptions regarding future commodity prices and expected production from our properties, any of which may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil, natural gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGL prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved, probable and possible reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved, probable and possible reserves and related valuations as of December 31, 2019 and 2018 were audited by CG&A and our estimates of proved, probable, and possible reserves and related valuations as of December 31, 2017 were prepared by CG&A. CG&A conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. For example, due to the deterioration in commodity prices in the first half of 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate our reserves estimates are likely to decline, which would in turn lower our reserve estimates. See “If oil, natural gas and NGL prices decline significantly, such as in the case of the significant decline in commodity prices in the first half of 2020, we could be required to record impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our shareholders’ equity.” A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from our reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the trailing twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

If oil, natural gas and NGL prices decline significantly, such as in the case of the significant decline in commodity prices in the first half of 2020, we could be required to record impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our shareholders’ equity.

Accounting rules require that we review the carrying value of our oil, natural gas and NGL properties for possible impairment at the end of each quarter. 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. The net capitalized costs of our proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of our proved oil, natural gas and NGL reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during periods of low commodity prices, such as those experienced in the first half of 2020. For example, if commodity prices remain depressed, we may be required to record a write off in the third quarter of 2020. Please see “Note 3—Oil and Gas Properties” to the condensed consolidated and combined financial statements of Brigham Minerals included elsewhere in this Quarterly Report. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil, natural gas and NGL prices increase the cost center ceiling applicable to the subsequent period. 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.

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A deterioration in general economic, business, political or industry conditions, such as those beginning in the first quarter of 2020, has materially adversely affected, and any further deterioration would materially adversely affect our results of operations, financial condition and free cash flow.

Recently, concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to significantly reduced economic activity and diminished expectations for the global economy. Additionally, recent acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. In addition, global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and demand for oil, natural gas and NGLs. For instance, the recent COVID-19 pandemic has materially adversely affected our business by, among other things, (i) reducing the demand for oil, natural gas and NGLs because of significantly reduced global and national economic activity, leading to lower prices for oil, natural gas and NGLs, and (ii) impairing the workforce and supply chain of certain of our operators. We cannot accurately predict the duration or magnitude of the effects of the COVID-19 pandemic on our business in the future. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in the first half of 2020 has led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad continues to deteriorate, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of our operators to continue operations and ultimately materially adversely impact our results of operations, financial condition and free cash flow.

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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)
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 June 30, 2020 formatted in iXBRL(Inline eXtensible Business Reporting Language): (i) Condensed Consolidated and Combined Balance Sheets, (ii) Condensed Consolidated and Combined Statement of Operations, (iii) Condensed Consolidated and Combined Statement of Changes in Shareholders' and Members' Equity, (iv) Condensed Consolidated and Combined Statement of Cash Flows and (v) Notes to the Condensed Consolidated and Combined Financial Statements, tagged as blocks of text.
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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* 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.

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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:

August 12, 2020

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