As confidentially submitted to the Securities and Exchange Commission on October 29, 2018

Registration No. 333-                

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 3

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Brigham Minerals, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1311	83-1106283
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)

5914 W. Courtyard Drive, Suite 100 Austin, Texas 78730 (512) 220-6350

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Blake C. Williams

Chief Financial Officer

5914 W. Courtyard Drive, Suite 100

Austin, Texas 78730

(512) 220-6350

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Douglas E. McWilliams Thomas G. Zentner Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222 David J. Miller Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

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 7(a)(2)(B) of the Securities Act.  ☐

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee(3)
Class A Common Stock, par value $0.01 per share	$	$

(1) Includes shares issuable upon exercise of the underwriters’ option to purchase additional shares.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(3) To be paid in connection with the initial filing of the registration statement.

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED                     , 2018

            Shares

Brigham Minerals, Inc.

Class A Common Stock

This is the initial public offering of our Class A common stock. We are selling                  shares of Class A common stock.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price of the Class A common stock is expected to be between $                 and $                 per share. We have applied to list our Class A common stock on the New York Stock Exchange under the symbol “MNRL.”

To the extent that the underwriters sell more than                  shares of Class A common stock, the underwriters have the option to purchase, exercisable within 30 days from the date of this prospectus, up to an additional                  shares from us at the public offering price less the underwriting discount and commissions.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Summary—Emerging Growth Company.”

Investing in our Class A common stock involves risks. See “Risk Factors” on page 28.

	Price to Public	Underwriting Discounts and Commissions(1)	Proceeds to Issuer
Per Share	$	$	$
Total	$	$	$

(1) See “Underwriting” for additional information regarding underwriting compensation.

Delivery of the shares of Class A common stock will be made on or about                     , 2018.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse Goldman Sachs & Co. LLC

Barclays	RBC Capital Markets
UBS Investment Bank	Wells Fargo Securities
Raymond James	Seaport Global Securities

Simmons Energy	Tudor, Pickering, Holt & Co.
A Division of Piper Jaffray

The date of this prospectus is                     , 2018.

TABLE OF CONTENTS

SUMMARY	1
RISK FACTORS	28
CAUTIONARY STATEMENT REGARDING FORWARD -LOOKING STATEMENTS	56
USE OF PROCEEDS	58
DIVIDEND POLICY	59
CAPITALIZATION	60
DILUTION	62
SELECTED HISTORICAL FINANCIAL DATA	64
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	66
BUSINESS	87
MANAGEMENT	113
EXECUTIVE COMPENSATION	120
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	128
CORPORATE REORGANIZATION	132
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	137
DESCRIPTION OF CAPITAL STOCK	140
SHARES ELIGIBLE FOR FUTURE SALE	146
CERTAIN ERISA CONSIDERATIONS	148
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS	151
UNDERWRITING	155
LEGAL MATTERS	162
EXPERTS	162
WHERE YOU CAN FIND MORE INFORMATION	162
INDEX TO FINANCIAL STATEMENTS	F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS	A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Through and including                     , 2018 (25 days after the date of this prospectus), all dealers effecting transactions in our Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

i

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

ii

SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our Class A common stock. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements, before investing in our Class A common stock. The information presented in this prospectus assumes, unless otherwise indicated, (i) an initial public offering price of $                 per share (the midpoint of the price range set forth on the cover of this prospectus) and (ii) that the underwriters’ option to purchase additional shares of Class A common stock is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our Class A common stock.

Brigham Minerals, Inc. (“Brigham Minerals”), the issuer in this offering, is a holding company formed to own an interest in, and act as the sole managing member of, Brigham Minerals Holdings, LLC (“Brigham LLC”). Brigham LLC will wholly own Brigham Resources, LLC (“Brigham Resources”), which wholly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”), which are Brigham Resources’ sole material assets, and also owns Brigham Resources Operating, LLC (“Brigham Operating”), which will be distributed to our Existing Owners (as defined below) prior to the completion of this offering. Accordingly, our historical financial statements are those of Brigham Resources, excluding the historical results and operations of Brigham Operating, which we refer to herein as our “predecessor.”

Unless indicated otherwise or the context otherwise requires, references in this prospectus to the “Company,” “us,” “we” or “our” (i) for periods prior to completion of this offering, refer to the assets and operations (including reserves, production and acreage) of Brigham Resources, excluding the historical results and operations of Brigham Operating, and (ii) for periods after completion of this offering, refer to the assets and operations of Brigham Minerals and its subsidiaries, including Brigham LLC, Brigham Resources and the Minerals Subsidiaries. This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in the “Glossary of Oil and Natural Gas Terms” contained in Annex A.

The estimates of our proved, probable and possible reserves as of June 30, 2018 and December 31, 2017 and 2016 have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineers. Summaries of CG&A’s reports are included as exhibits to the registration statement of which this prospectus forms a part.

Our Company

Overview

We formed our company in 2012 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 basins across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our shareholders by both capturing growth in free cash flow from the continued development of our existing portfolio of 10,187 undeveloped horizontal drilling locations unburdened by development capital expenditures or lease operating expenses, as well as leveraging our highly experienced technical evaluation team to continue to execute upon our scalable business model of sourcing, methodically evaluating and integrating accretive minerals acquisitions in the core of top-tier, liquids-rich resource plays.

Our portfolio is comprised of mineral and royalty interests across four of the most highly economic, liquids-rich resource basins in the continental United States, including the Permian Basin in Texas and New Mexico, the SCOOP and STACK plays in the Anadarko Basin of Oklahoma, the Denver-Julesburg (“DJ”) Basin in Colorado

1

and Wyoming and the Williston Basin in North Dakota. Our highly technical approach towards mineral acquisitions in the geologic core of top-tier resource plays has purposefully led to a concentrated portfolio covering 37 of the most highly active counties for horizontal drilling in the continental United States. According to RS Energy Group (“RSEG”), as of June 30, 2018, operators have deployed 59% of the horizontal rig fleet, and 66% of the liquids-focused horizontal rig fleet, in the continental United States in these same 37 counties, which we believe will continue to result in the consistent long-term development of our asset base. On a pro forma basis giving effect to our portfolio of 61,219 net royalty acres at June 30, 2018 as if we had owned it since January 1, 2013, we estimate that the production volumes net to our interests would have grown at an approximate 53% compound annual growth rate, or CAGR, from the beginning of 2013 through June 30, 2018, despite crude oil prices decreasing substantially during that same time period, as illustrated by the following chart.

Since inception, we have executed on our technically driven, disciplined acquisition approach and have closed 1,229 transactions with third-party mineral and royalty interest owners as of June 30, 2018. Over the past four and a half years, we have increased our mineral and royalty interests from 10,209 net royalty acres as of December 31, 2013, to 61,219 net royalty acres as of June 30, 2018, which represents a 49% compound annual growth rate in our mineral and royalty interests over that period. See “—Our Company—Our Mineral and Royalty Interests” for a discussion of how we calculate net royalty acres.

The following table summarizes certain information regarding our net royalty acreage acquisitions during each year of our operations and for the six months ended June 30, 2018.

	2012		2013		2014		2015		2016		2017		2018(1)		Total
Net Royalty Acres (NRAs) Acquired		473		9,736		17,317		7,192		9,791		9,361		7,349		61,219
Number of Acquisitions		15		313		380		152		121		153		95		1,229
Average NRAs per Acquisition		32		31		46		47		81		61		77		50
NRAs at Period End		473		10,209		27,526		34,718		44,509		53,870		61,219		61,219

(1) As of June 30, 2018.

2

By targeting core, top-tier acreage, our interests have continued to see rapid development with a total of approximately 662 horizontal wells spud on our mineral and royalty interests during 2017. This significant activity has similarly translated into rapid production growth with our production volumes growing approximately 68% from 2016 to 2017. Further, our production volumes are comprised of high-value liquids with 69% of our volumes for the six months ended June 30, 2018 composed of crude oil and natural gas liquids (“NGLs”), which represents 87% of our mineral and royalty revenue for the period. The combined growth in our production volumes and the high percentage of liquids production have resulted in a 114% increase in our royalty revenue from 2016 to 2017. We expect to see future organic growth in our production, revenue and free cash flow from 586 drilled but uncompleted horizontal wells (“DUCs”) across our interests and approximately 751 horizontal drilling permits as of June 30, 2018 (excluding Laramie County, Wyoming), all of which are expected to occur without additional capital expenditure outlays. Development of permits on our acreage is driven by robust and consistent rig activity on meaningful portions of our acreage. Over the twelve months ended June 30, 2018, there have been an average of 27 horizontal rigs developing 865 net mineral acres across our basins, which we believe provides visibility toward future production growth.

Average Monthly Rigs on Acreage	Average Monthly NMA Under Development

In addition to existing near-term development, our permitted horizontal drilling locations represent only approximately 7% of the remaining proved, probable and possible undeveloped horizontal drilling locations incorporated by CG&A in our reserve report as of June 30, 2018, thereby providing us with a substantial long-term drilling inventory on our acreage.

As indicated by the following table, from 2016 to 2017, the gross number of wells spud and wells turned to production on our acreage increased by 76% and 97%, respectively, as our average realized prices for oil, natural gas and NGLs increased by 24.5%, 22.9% and 48.9%, respectively. During that same period, however, the number of wells spud and turned to production on our acreage as a percentage of the total number of wells spud and completed in our basins remained relatively unchanged. We believe this consistency is an indication that our assets are located in the core of our resource plays and that operators will continue deploying rigs and capital to develop our existing mineral and royalty interests, even in low commodity price environments. Based solely on the 662 horizontal wells spud on our acreage during 2017 and our 10,187 total gross undeveloped horizontal drilling locations as of June 30, 2018, we believe we have over 15 years of organic drilling inventory.

	2016							2017
	On Our Acreage		Total Across Basins		Our Share of Total			On Our Acreage		Total Across Basins		Our Share of Total
Wells Spud		376		4,127		9	%		662		7,131		9	%
Wells Turned to Production		277		4,075		7	%		547		6,753		8	%

3

Our management team has a long history of identifying, acquiring, delineating, developing and successfully monetizing positions in liquids-rich resource basins. Prior to forming Brigham Resources, a subset of our management team formed Brigham Exploration Company (“Brigham Exploration”), where it oversaw the identification, acquisition, delineation and development of approximately 375,000 net acres in the Williston Basin prior to Brigham Exploration’s sale to Statoil ASA (“Statoil”) in December 2011 for $4.4 billion. Our team utilized its technical capabilities in the Williston Basin to identify and acquire highly prospective leasehold acreage with favorable geologic attributes and employed advanced drilling and completion technologies to cost-effectively extract oil and natural gas. Immediately following the sale of Brigham Exploration, a subset of our management team then formed Brigham Operating and executed on these same strategies in the Southern Delaware Basin in West Texas. By applying rigorous geologic evaluation criteria, Brigham Operating was an early entrant in the Southern Delaware Basin in Pecos County, Texas, where it assembled an approximate 80,185 net acre leasehold position in a largely contiguous block. Brigham Operating sold these assets to Diamondback Energy, Inc., in February 2017 for approximately $2.55 billion.

Our Mineral and Royalty Interests

Mineral interests are real-property interests that are typically perpetual and grant both ownership of the oil, natural gas and NGLs under a tract of land and the right to lease development rights to a third party. When those rights are leased, usually for a three-year primary term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a percentage of production or revenue. In addition to mineral interests, which represented approximately 97% of our net royalty acres as of June 30, 2018, we also own other types of interests, including nonparticipating royalty interests (“NPRIs”) and overriding royalty interests (“ORRIs”). ORRIs burden the working interest ownership of a lease and represent the right to receive a fixed percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated lease expires and are therefore not perpetual in nature. Please see “Business—Our Mineral and Royalty Interests.”

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. Mineral and royalty owners only incur their proportionate share of severance and ad valorem taxes, as well as in some instances, gathering, transportation and marketing costs. As a result, operating margins and therefore free cash flow for a mineral and royalty interest owner are higher as a percentage of revenue than for a traditional exploration and production operating company.

As of June 30, 2018, our mineral and royalty interests consisted of 42,572 net mineral acres, which have been leased to operators to explore for and develop our oil and natural gas rights at a weighted average royalty of 18.0%. Typically, within the minerals industry, mineral owners standardize ownership to a 12.5%, or 1/8^th, royalty interest, which is referred to as a “net royalty acre.” Our net mineral acres standardized to a 1/8^th royalty equate to 61,219 net royalty acres. When standardized on a 100% royalty basis, these 61,219 net royalty acres equate to 7,652 “100% royalty acres.” Our 61,219 net royalty acres are located within 1,216 drilling spacing units (“DSUs”), which are the areas designated in a spacing order or unit designation as a unit and within which operators drill wellbores to develop our oil and natural gas rights. Our DSUs, in aggregate, consist of a total of 1,260,350 gross acres, which we refer to as our “gross DSU acreage.” Within our gross DSU acreage, we expect to have an interest in wells currently producing or that will be drilled in the future. The following table summarizes our mineral and royalty interest position and the conversion of our interests between net mineral acres, net royalty acres and 100% royalty acres as of June 30, 2018.

Net Mineral Acres	Weighted Average Royalty			Net Royalty Acres(1)		100% Royalty Acres(2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well(3)
42,572		18.0	%		61,219		7,652		1,260,350		0.61	%

4

(1) Standardized to a 1/8^th royalty (i.e., 42,572 net mineral acres * 18.0% / 12.5%).

(2) Standardized to a 100% royalty (i.e., 61,219 net royalty acres * 12.5%).

(3) Calculated as number of 100% royalty acres per gross DSU acre (i.e., 7,652 100% royalty acres / 1,260,350 gross DSU acres).

Our Properties

Focus Areas

Our mineral and royalty interests are primarily located in six resource plays, which we refer to as our focus areas. These include the Delaware and Midland Basins in the Permian Basin, the SCOOP and STACK plays in the Anadarko Basin, the DJ Basin and the Williston Basin. The following chart shows our overall exposure to each of our primary focus areas based on our net royalty acres in each focus area as of June 30, 2018.

In addition, the following table summarizes certain information regarding our primary focus areas. Our average daily net production for the three months ended June 30, 2018 was comprised 53% of oil production, 31% of natural gas production and 16% of NGL production.

Basin	Acreage as of June 30, 2018														Gross Horizontal Producing Well Count as of June 30, 2018(4)		Average Daily Net Production for Three Months Ended June 30, 2018(5) (Boe/d)
	Net Mineral Acres		Weighted Average Royalty			Net Royalty Acres(1)		100% Royalty Acres(2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well(3)
Delaware		9,794		21.3	%		16,691		2,086		179,383		1.16	%		258		908
Midland		2,127		15.6	%		2,659		332		49,938		0.67	%		52		116
SCOOP		5,251		18.5	%		7,777		972		161,247		0.60	%		240		215
STACK		5,889		17.8	%		8,373		1,047		159,970		0.65	%		156		416
DJ		11,945		15.9	%		15,224		1,903		160,897		1.18	%		733		1,452
Williston		5,160		16.3	%		6,747		843		471,685		0.18	%		1,238		544
Other		2,406		19.5	%		3,748		469		77,230		0.61	%		62		72
Total		42,572		18.0	%		61,219		7,652		1,260,350		0.61	%		2,739		3,723

5

Note: Individual amounts may not add up to totals due to rounding.

(1) Standardized to a 1/8^th royalty.

(2) Standardized to a 100% royalty.

(3) Calculated as number of 100% royalty acres per gross DSU acre.

(4) Represents number of horizontal producing wells across all DSUs in which we participate.

(5) Represents actual production plus allocated accrued volumes attributable to the period presented.

Permian Basin—Delaware and Midland Basins

The Permian Basin ranges from West Texas into southeastern New Mexico and is currently the most active area for horizontal drilling in the United States. The Permian Basin is further subdivided into the Delaware Basin in the west and the Midland Basin in the east. As of June 30, 2018, according to RSEG, there were approximately 226 and 150 horizontal rigs running in the Delaware and Midland Basins, respectively. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Delaware Basin are prospective for seven or more producing zones of economic horizontal development including the Wolfcamp A, B, C and XY; First, Second and Third Bone Spring; and the Avalon. Our Delaware Basin mineral and royalty interests are located in Reeves, Loving, Ward, Pecos, Culberson and Winkler Counties, Texas with our remaining interests located in Lea County, New Mexico. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Midland Basin are prospective for five or more producing zones of economic horizontal development including the Middle Spraberry; Lower Spraberry; and Wolfcamp A, B and C. Our Midland Basin mineral and royalty interests are located in Martin, Midland, Upton, Howard and Reagan Counties, Texas.

Anadarko Basin—SCOOP and STACK Plays

The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens and McClain Counties. As of June 30, 2018, according to RSEG, there were approximately 71 horizontal rigs running in the SCOOP play. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the SCOOP play are prospective for two or more producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo and Blaine Counties. As of June 30, 2018, according to RSEG, there were approximately 27 horizontal rigs running in the STACK play. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the STACK play are prospective for four or more producing zones of economic horizontal development including multiple benches within both the Meramec and Woodford formations.

DJ Basin

The DJ Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. As of June 30, 2018, according to RSEG, there were approximately 26 horizontal rigs running in the DJ Basin. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the DJ Basin are prospective for four or more producing zones of economic horizontal development including the Niobrara A, B and C and Codell formations.

6

Williston Basin

The Williston Basin stretches from western North Dakota into eastern Montana with the majority of operator horizontal drilling activity located in Mountrail, Williams, and McKenzie Counties, North Dakota. As of June 30, 2018, according to RSEG, there were approximately 51 horizontal rigs running in the Williston Basin. Based on our geologic and engineering interpretations as well as current operator delineation efforts, we believe our mineral and royalty interests are prospective for two or more producing zones of economic horizontal development including the Bakken and multiple Three Forks benches. The majority of our interests are located in Mountrail, Williams and McKenzie Counties with additional interests owned in Divide, Burke, Dunn, Billings and Stark Counties, North Dakota and Richland County, Montana.

Other Counties

Our other interests are comprised of mineral and royalty interests owned in Carter and Love Counties, Oklahoma in what we refer to as the Extended Woodford play in the Marietta and Ardmore Basins and in Bradford, Sullivan and Washington Counties, Pennsylvania in the Marcellus and Utica Shale plays. Our interests in Carter and Love Counties are largely being developed by Exxon Mobil Corporation through their operating subsidiary XTO Energy, which currently has four horizontal rigs operating in the area. Our interests in Pennsylvania are largely being developed by Range Resources Corporation and Chief Oil & Gas LLC.

For more detailed information about the basins and regions described above, please read “Business—Our Properties—Focus Areas.”

Prospective Undeveloped Horizontal Drilling Locations

We believe our production and free cash flow will grow through the drilling of the substantial undeveloped organic inventory of horizontal drilling locations located on our acreage. As of June 30, 2018, as reflected in our reserve report prepared by CG&A, we have identified 10,187 gross proved, probable and possible undeveloped horizontal drilling locations across our gross DSU acreage. Furthermore, we believe additional optionality is possible through the delineation of additional horizontal formations including the Wolfcamp D and Jo Mill in the Permian Basin and the SCORE in the SCOOP and STACK plays which are not currently reflected in our reserve reports as well as downspacing in existing formations. Nearly 45% of our total net horizontal undeveloped locations are located in the Delaware and Midland Basins, with another 24% located in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma, as shown in the following table.

	Gross Horizontal Undeveloped Locations		Percentage of Total Portfolio			Net Horizontal Undeveloped Locations		Percentage of Total Portfolio
Delaware Basin		2,725		27	%		34.6		38	%
Midland Basin		626		6	%		6.0		7	%
SCOOP		1,036		10	%		6.9		7	%
STACK		1,697		17	%		15.6		17	%
DJ Basin		1,765		17	%		22.6		25	%
Williston		1,712		17	%		3.1		3	%
Other		626		6	%		3.2		3	%
Total		10,187		100	%		92.0		100	%

7

Additionally, the following table provides a detailed summary of our inventory of horizontal drilling locations as of June 30, 2018.

Productive Horizons	Gross Horizontal Undeveloped Locations(1)		Total Gross Horizontal Locations(2)		DSUs(3)(4)		Gross Horizontal Undeveloped Locations Per DSU(4)		Total Gross Horizontal Locations Per DSU(4)		Net Horizontal Undeveloped Locations(5)
Delaware Basin
Wolfcamp A		1,249		1,455		226		5.5		6.4		17.8
Wolfcamp B		525		569		172		3.1		3.3		8.7
3rd BS/WC XY		399		469		144		2.8		3.3		2.7
2nd Bone Spring		244		259		86		2.8		3.0		1.5
Avalon		118		129		50		2.4		2.6		0.6
Other		190		200		54		3.5		3.7		3.3
Total		2,725		3,081		226		12.1		13.6		34.6
Midland Basin
Wolfcamp A		156		191		53		2.9		3.6		1.5
Wolfcamp B		151		189		50		3.0		3.8		1.5
Lower Spraberry		234		250		53		4.4		4.7		2.1
Other		85		91		23		3.7		4.0		0.9
Total		626		721		53		11.8		13.6		6.0
SCOOP
Woodford		744		975		149		5.0		6.5		4.9
Springer		292		324		78		3.7		4.2		2.0
Total		1,036		1,299		149		7.0		8.7		6.9
STACK
Woodford		898		998		144		6.2		6.9		7.7
Meramec		799		912		116		6.9		7.9		7.9
Total		1,697		1,910		161		10.5		11.9		15.6
DJ Basin
Niobrara		1,302		1,992		184		7.1		10.8		16.8
Codell		463		655		138		3.4		4.7		5.8
Total		1,765		2,647		184		9.6		14.4		22.6
Williston Basin
Bakken		785		1,637		340		2.3		4.8		1.3
Three Forks		927		1,525		340		2.7		4.5		1.8
Total		1,712		3,162		343		5.0		9.2		3.1
Other		626		692		100		6.3		13.1		3.2
Grand Total		10,187		13,512		1,216		8.4		11.1		92.0

(1) Represents gross horizontal drilling locations across our gross DSU acreage.

(2) Includes all undeveloped and developed wells in each horizon.

(3) Represents the aggregate number of DSUs covering any of the applicable productive horizons as identified by CG&A.

(4) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU (i.e., not all horizons are booked in all DSUs).

(5) A net well represents 100% net revenue interest in a single gross well.

8

Third-Party Operators

Beyond our technical analysis to identify core, highly economic areas, an additional critical aspect of our evaluation process is to acquire mineral and royalty interests that will be drilled and completed by operators we believe will outperform their peers through the application of the latest drilling and completion technologies in each of our operating basins. The following chart summarizes our exposure to these operators based on the percentage of our net interests in the wells to be drilled by each operator.

9

In addition, the following table shows our exposure to each of these operators broken down by our primary focus areas based on the percentage of our net interests in the wells to be drilled by each operator as of June 30, 2018.

	Percentage as of June 30, 2018
Operator	Total Portfolio		Delaware		Midland		SCOOP		STACK		DJ Basin		Williston		Other
Noble Energy		10%		16%		—		—		—		16%		—		—
Anadarko Petroleum		8%		13%		—		—		—		15%		—		—
Newfield Exploration		7%		—		—		25%		16%		—		3%		57%
Continental Resources		5%		—		—		47%		2%		—		16%		17%
XTO		4%		9%		1%		—		—		—		5%		16%
Devon Energy		4%		*		—		—		22%		—		—		—
Whiting Petroleum		3%		—		—		—		—		13%		4%		—
Marathon Oil		3%		—		—		16%		12%		—		2%		*
Pioneer Natural Resources		3%		—		50%		—		—		—		—		—
PDC Energy		3%		1%		—		—		—		10%		—		—
Extraction Oil and Gas		3%		—		—		—		—		11%		—		—
Cimarex Energy		3%		3%		—		—		10%		—		—		—
EOG Resources		3%		1%		—		*		—		9%		4%		—
Patriot Resources		2%		6%		—		—		—		—		—		—
Diamondback Energy(1)		2%		3%		13%		—		—		—		—		—
Chevron Corporation		2%		5%		—		—		—		—		—		—
Halcon Resources		2%		6%		—		—		—		—		2%		—
Concho Resources		2%		4%		*		—		—		—		—		—
BP(2)		2%		6%		—		—		—		—		—		—
Occidental Petroleum		1%		4%		1%		—		—		—		—		—
Subtotal		72%		75%		65%		88%		62%		74%		37%		90%
Other Operators		28%		25%		35%		12%		38%		26%		63%		10%
Total		100%		100%		100%		100%		100%		100%		100%		100%

Note: Individual amounts may not add up to totals due to rounding.

* Less than 1%.

(1) Pro forma for Diamondback Energy’s acquisition of Energen Resources Corporation.

(2) Pro forma for BP’s acquisition of BHP Billiton Ltd.’s U.S. shale business.

Business Strategies

Our primary business objective is to deliver an attractive risk-adjusted total return to our shareholders through (i) the growth of our free cash flow generated from our existing portfolio of approximately 61,219 net royalty acres, and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. We intend to accomplish this objective by executing the following strategies:

• Capture growth in free cash flow through continued development of our mineral and royalty interests. We have targeted assets in the core of highly economic, liquids-rich resource plays, and we expect operators to continue deploying rigs and capital to develop our existing mineral and royalty interests, even in low commodity price environments. As of June 30, 2018, there were 586 DUCs across our acreage position, representing 8% of the DUCs estimated by the U.S. Energy Information Administration (the “EIA”) in the continental United States. We believe this DUC inventory will contribute to our near-term free cash flow growth as operators complete and turn these DUCs to sales. Further, we expect to generate future free cash flow growth from ongoing drilling and permitting activity on our interests. Since inception, our interests have been actively drilled, with a total of 2,739 producing horizontal wells on our gross DSU acreage over the period. Over the twelve months ended June 30, 2018, there were an average

10

of 27 rigs deployed across our acreage, with an average of approximately 865 net mineral acres under development per month. Additionally, operators continue to actively permit our interests, with approximately 80 new gross drilling permits issued per month over the last 12 months and a total of approximately 751 existing gross permitted drilling locations yet to be drilled across our gross DSU acreage as of June 30, 2018 (excluding Laramie County, Wyoming). As a result, we believe that our assets are positioned to provide substantial near- and long-term free cash flow growth without exposure to incremental capital expenditures or lease operating expenses associated with ongoing development.

• Target a portfolio in the core areas of highly economic, liquids-rich resource plays under premier operators. Our growing portfolio is driven by our acquisition strategy focused on core positions in top-tier, high-return, liquids-rich resource plays that we believe will continue to attract development capital throughout commodity price cycles. Our targeted approach has led us to acquire mineral and royalty interests in 37 selected counties that we consider to be some of the most economically prospective in the country, with 59% of the entire horizontal rig fleet in the continental United States active within those counties as of June 30, 2018. Based on an assumed $6 million per well, we estimate that operators deployed approximately $44.3 billion in drilling and completion capital expenditures to those counties during 2017 and $2.1 billion in drilling and completion capital expenditures to our gross DSU acreage. We believe that our focus on acquiring assets in the core of resource plays will also help to mitigate any negative impact of possible future declines in oil and natural gas prices, as operators have historically continued to deploy rigs and capital to these core areas even in lower commodity price environments. As an example, had we owned our portfolio of 61,219 net royalty acres as of June 30, 2018 since January 1, 2013, we estimate that the pro forma production volumes net to our interests would have grown at an approximate 53% compound annual growth rate from the beginning of 2013 through June 30, 2018, despite average crude oil prices during the first half of 2018 decreasing by 33% compared to the year ended December 31, 2013.

• Leverage exploration and production technical expertise to evaluate acquisition opportunities. Our team’s technical expertise and extensive experience with exploration and production companies (i.e., operators) allows us to identify and acquire core mineral and royalty interests that we believe will be developed by premier operators. Our technical evaluation process for a potential mineral and royalty interest acquisition includes, but is not limited to, an evaluation of the following with respect to the associated mineral and royalty interests: (i) the existing producing wells, (ii) the number of productive formations anticipated to be developed, (iii) the number of wells anticipated to be developed per productive formation, (iv) the forecasted estimated ultimate recovery (“EUR”) of all wells per productive formation, (v) the oil and natural gas composition per productive formation and (vi) the anticipated performance of the operator expected to develop the interest. We analyze and estimate the economic returns of the operators to better understand the quality of the mineral interests relative to their other assets. We also evaluate operator performance relative to peers and formulate a drilling timeline, which is typically based on operator activity levels within a resource play and indications by that operator in public or regulatory filings regarding its future drilling and completion activities. As of June 30, 2018, we estimate that 75% of our undeveloped net wells will be drilled by operators who are currently running five or more rigs in the continental United States. If a potential transaction is comprised of multiple DSUs, we evaluate each DSU individually. We believe that acquiring mineral and royalty interests in core areas under top-performing, active operators enhances the probability that our undeveloped mineral and royalty interests will be converted to producing locations that will continue to generate free cash flow growth.

• Capitalize on strong acquisition sourcing network. Our team leverages its extensive network of acquisition sources, including contacts developed during the 20 years prior to our formation while working as exploration and production operators as well as those developed since our formation in 2012. Since inception, we have sourced and originated a significant number of potential transactions and,

11

through our rigorous underwriting and evaluation process, closed 1,229 mineral and royalty transactions. We believe we have developed a reputation in the minerals industry as a responsive, efficient and reliable acquirer, which continues to provide us consistent transaction opportunities in each of our target basins. During 2017, we increased our mineral and royalty interests by 21% or 9,361 net royalty acres. During 2018, we closed our largest single acquisition to date for an aggregate purchase price of approximately $41 million, subject to customary post-closing adjustments, consisting of mineral and royalty interests in the Delaware Basin in Loving County, Texas and Lea County, New Mexico, under highly active, premier operators. As a public entity, we will continue to source transactions in the most attractive areas based on our analysis, with the objective of becoming a premier consolidator of mineral and royalty interests in the United States.

• Maintain financial flexibility via conservative capital structure. We are committed to maintaining a conservative capital structure that will provide us with the financial flexibility to execute our acquisition strategy. Upon completion of this offering, we will have limited indebtedness and believe the proceeds from this offering, cash from operations, $60 million of available borrowings under our term loan facility and future potential access to the public capital markets will provide us with sufficient liquidity and financial flexibility to execute accretive acquisitions to further grow our production and free cash flow.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and to achieve our primary business objectives:

• Experienced, technically focused team with significant mineral and royalty interest acquisition history and value-creation track record. Our management team has a proven track record of driving total return for shareholders, including sourcing opportunities, executing accretive acquisitions, maximizing asset development and monetizing assets. We have assembled a team of over 25 dedicated professionals, including a technical staff comprised of nine full-time, highly experienced geologists and reservoir engineers who apply a methodical evaluation approach focused on the same criteria as would an operator, while maintaining long-term disciplined underwriting criteria to target transactions in the core areas of liquids-rich resource basins. Our portfolio has been assembled over the past six years through the completion of over 1,229 transactions. Through June 30, 2018, our team has assembled 61,219 net royalty acres in the core areas of premier, liquids-rich resource plays, and we intend to continue being an active acquirer of mineral and royalty interests in the future. We believe our team’s track record of success is exemplified by the historical value that has been created for public and private shareholders of both Brigham Exploration and Brigham Operating through the early-stage identification, acquisition and monetization of positions in liquids-rich resource plays in the Williston Basin and Southern Delaware in the Permian Basin, ultimately resulting in the sale of Brigham Exploration’s and Brigham Operating’s assets for an aggregate of $7.0 billion. Furthermore, during its time as a public company, Brigham Exploration’s enterprise value grew from $117.5 million at the time of its initial public offering to its eventual sale to Statoil for $4.4 billion.

• Minerals and royalties are a perpetual asset class unburdened by both development capital expenditures and lease operating expenses, thereby driving significant free cash flow. Our mineral interests are a perpetual right to a fixed percentage of royalty revenues from the oil, natural gas and NGLs extracted from our interests. As a mineral and royalty owner, we do not incur any of the capital commitments related to drilling the undeveloped horizontal inventory on our interests, the ongoing lease operating expenses as minerals on our acreage are produced or the potential environmental or operational liabilities related to maintaining oil, natural gas and NGL production, including workovers and other well remediation and abandonment costs. As a result, we benefit from organic free cash flow growth associated with our mineral and royalty interests and believe that we realize higher margins over time with less exposure to risks than an exploration and production company. Finally, due to the perpetual

12

nature of our mineral interests and the lack of future development costs, we benefit from: (i) the development of additional producing formations underlying our interests as operators delineate different horizons, (ii) the drilling of additional wells per producing formation as operators determine optimal well spacing, (iii) improved EURs as operators continuously improve drilling and completion techniques, and (iv) incremental lease bonus payments when we have the opportunity to lease existing open acreage or to re-lease acreage that has expired or is not held by production under the terms of our leases.

• Multi-year drilling inventory in the core of four active liquids-rich resource basins. As of June 30, 2018, we had interests in approximately 2,739 producing horizontal wells across 1,216 identified DSUs, or an average of 2.3 producing horizontal wells per DSU, as reflected in our reserve report prepared by CG&A. As reflected in that same reserve report, 10,187 horizontal drilling locations are yet to be drilled by operators across those 1,216 DSUs, which we believe will drive future free cash flow growth. These undeveloped horizontal drilling locations are located across (i) four liquids-rich, target basins including the Permian, SCOOP/STACK plays in the Anadarko, DJ and Williston; (ii) a diverse portfolio of operators including Noble Energy, Inc. (“Noble”), Anadarko Petroleum Corporation (“Anadarko”), Newfield Exploration Company (“Newfield”) and Continental Resources, Inc. (“Continental”); and (iii) a number of productive formations including the Wolfcamp, Bone Spring, Avalon, Woodford, Springer, Meramec, Niobrara, Codell, Bakken and Three Forks benches. In addition, we expect operators will continue to delineate additional geologic zones and optimize well spacing across our acreage, leading to incremental locations that we do not currently include in our inventory.

• Portfolio of high-quality operators developing our position. We expect our mineral and royalty interests to be converted from undeveloped to producing by a portfolio of high-quality operators who deploy the latest drilling and completion technologies and have significant access to capital, including Noble, Anadarko, Newfield and Continental, as well as other best-in-class operators throughout our core areas. As of June 30, 2018, we have exposure to the top three operators by permit, drilling activity and gross operated production in each of the plays in which our mineral and royalty interests are located. As of June 30, 2018, we estimate that 75% of our undeveloped net wells will be drilled by operators who are currently running five or more rigs in the continental United States. Because of our exposure to the most active operators within the core of each of our basins, we believe that capital will continue to be deployed in low commodity price environments to convert our drilling inventory into producing locations, thereby increasing our free cash flow.

Corporate Reorganization

Corporate Restructuring

Brigham Minerals was incorporated as a Delaware corporation in June 2018 by an affiliate of Warburg Pincus LLC (“Warburg Pincus”). Brigham Minerals and certain entities affiliated with Warburg Pincus, Yorktown Partners LLC (“Yorktown”) and Pine Brook Road Advisors, LP (“Pine Brook”), our management and our other investors (collectively, the “Existing Owners”) currently, directly or indirectly through Brigham Minerals, own all of the membership interests in Brigham LLC, which in turn indirectly owns all of the outstanding membership interests in the Minerals Subsidiaries.

Brigham Minerals acquired an indirect interest in Brigham Resources on July 16, 2018 in a series of restructuring transactions that are collectively referred to in this prospectus as the “July 2018 restructuring.” In the July 2018 restructuring, certain entities affiliated with Warburg Pincus contributed all of their respective interests in certain wholly owned “blocker” 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 contribution agreement effecting the July 2018 restructuring is filed as an exhibit to the registration statement of which this prospectus forms a part. As a result of the July 2018 restructuring, Brigham Minerals became wholly

13

owned by certain entities affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a membership interest in Brigham Resources. The other Existing Owners held all of the remaining outstanding membership interests of Brigham Resources.

Prior to the offering, Brigham Resources will undergo a second series of restructuring transactions that are collectively referred to in this prospectus as the “October 2018 restructuring.” In the October 2018 restructuring, Brigham Resources will become a wholly owned subsidiary of Brigham LLC, which will be a wholly owned subsidiary of Brigham Equity Holdings, LLC (“Brigham Equity Holdings”), and Brigham Equity Holdings will be wholly owned by the Existing Owners, directly or indirectly through Brigham Minerals. As a result of the foregoing transactions, there will be no change in the control or economic interests of the Existing Owners in Brigham Resources, although their ownership will be indirect through Brigham Equity Holdings and its wholly owned subsidiary Brigham LLC.

Following this offering and the reorganization transactions described below (our “corporate reorganization”), Brigham Minerals will be a holding company whose sole material asset will consist of a     % interest in Brigham LLC, which will wholly own Brigham Resources. Brigham Resources will continue to wholly own the Minerals Subsidiaries, which own all of our operating assets. After the consummation of the transactions contemplated by this prospectus, Brigham Minerals will be the sole managing member of Brigham LLC and will be responsible for all operational, management and administrative decisions relating to Brigham LLC’s business.

Prior to our corporate reorganization, all of the interests in Brigham Operating will be distributed, directly or indirectly, to the Existing Owners. As a result, neither Brigham Minerals nor Brigham LLC will own any direct or indirect interest in Brigham Operating at the time of the offering.

In connection with this offering,

• Brigham Equity Holdings will distribute all of its equity interests in Brigham LLC, other than its interests in Brigham LLC attributable to certain unvested incentive units in Brigham Equity Holdings, to the Existing Owners (which will result in the ownership in Brigham LLC of our Existing Owners with respect to unvested incentive units remaining consolidated in Brigham Equity Holdings);

• all of the outstanding membership interests in Brigham LLC will be converted into a single class of common units in Brigham LLC, which we refer to in this prospectus as “Brigham LLC Units”;

• Brigham Minerals will issue                  shares of Class A common stock to purchasers in this offering in exchange for the proceeds of this offering;

• Each holder of Brigham LLC Units following the restructuring (a “Brigham Unit Holder”), other than Brigham Minerals and its subsidiaries, will receive a number of shares of Class B common stock equal to the number of Brigham LLC Units held by such Brigham Unit Holder following this offering; and

• Brigham Minerals will contribute the net proceeds of this offering to Brigham LLC in exchange for an additional number of Brigham LLC Units such that Brigham Minerals holds a total number of Brigham LLC Units equal to the number of shares of Class A common stock outstanding following this offering.

After giving effect to these transactions and this offering and assuming the underwriters’ option to purchase additional shares is not exercised:

• the Existing Owners will own all of our Class B common stock, representing     % of our capital stock;

• the Existing Owners will own                  shares, or     %, of our Class A common stock, representing     % of our capital stock;

14

• investors in this offering will own                  shares, or     %, of our Class A common stock, representing     % of our capital stock;

• Brigham Minerals will own an approximate     % interest in Brigham LLC; and

• the Existing Owners will own an approximate     % interest in Brigham LLC.

If the underwriters’ option to purchase additional shares is exercised in full:

• the Existing Owners will own all of our Class B common stock, representing     % of our capital stock;

• the Existing Owners will own                  shares, or     %, of our Class A common stock, representing     % of our capital stock;

• investors in this offering will own                  shares, or     %, of our Class A common stock, representing     % of our capital stock;

• Brigham Minerals will own an approximate     % interest in Brigham LLC; and

• the Existing Owners will own an approximate     % interest in Brigham LLC.

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list Class B common stock on any exchange.

Following this offering, under the First Amended and Restated Limited Liability Company Agreement of Brigham LLC (the “Brigham LLC Agreement”), each Brigham Unit Holder will, subject to certain limitations, have the 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 the right (the “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. 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. See “Certain Relationships and Related Party Transactions—Brigham LLC Agreement.” The Existing Owners will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

15

The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

(1) See “Corporate Reorganization—Existing Owners’ Ownership” for a discussion of the interests held by Existing Owners.

We have granted the underwriters a 30-day option to purchase up to an aggregate of              additional shares of Class A common stock. Any net proceeds received from the exercise of this option will be used to fund future acquisitions of mineral and royalty interests.

Our Principal Stockholders

We have valuable relationships with Warburg Pincus, Yorktown and Pine Brook, private investment firms focused on investments in the energy sector. Upon completion of this offering, affiliates of Warburg Pincus, Yorktown and Pine Brook (collectively, our “Sponsors”) will own approximately              shares of Class A

16

common stock and                  shares of Class B common stock, representing approximately     % of the voting power of Brigham Minerals, and                  Brigham LLC Units. Please see “Security Ownership of Certain Beneficial Owners and Management.”

Warburg Pincus is a leading global private equity firm focused on growth investing. The firm has more than $46 billion in private equity assets under management. Its active portfolio of more than 170 companies is highly diversified by stage, sector and geography. Warburg Pincus is an experienced partner to management teams seeking to build durable companies with sustainable value. Founded in 1966, Warburg Pincus has raised 17 private equity funds that have invested over $68 billion in over 825 companies in more than 40 countries. Since the late 1980s, Warburg Pincus has invested more than $13 billion in energy and natural resources companies around the world. The firm is headquartered in New York with offices in Amsterdam, Beijing, Hong Kong, Houston, London, Luxembourg, Mumbai, Mauritius, San Francisco, São Paulo, Shanghai and Singapore.

Yorktown is a private investment firm founded in 1991. Focused on investments in the energy sector, Yorktown makes growth capital and buyout investments in the business of oil and natural gas production, pipelines, gathering systems and processing/fractionation plants, energy-related manufacturing and services and metals and mining. Yorktown has raised eleven energy funds totaling over $8 billion that has been invested in over 110 companies. The firm is headquartered in New York.

Pine Brook is an investment firm that manages more than $6 billion of limited partner commitments. Pine Brook focuses on making “business building” investments, primarily in energy and financial services businesses. Pine Brook’s team of investment professionals collectively has over 300 years of experience financing the growth of businesses with equity, working alongside talented entrepreneurs and experienced management teams to build businesses of scale without relying on acquisition leverage. Over its 12-year investment history, Pine Brook has led or co-led 55 investments in the energy and financial services sectors, totaling over $10.6 billion in capital invested. In addition to Brigham Minerals, Pine Brook has invested in 28 energy companies. The firm is headquartered in New York with an office in Houston.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, we may take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise generally applicable to other public companies. These exemptions include:

• an exemption from providing an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

• an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”), requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

• an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise; and

• reduced disclosure of executive compensation.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting

17

standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

We will cease to be an “emerging growth company” upon the earliest of (i) when we have $1.07 billion or more in annual revenues; (ii) when we issue more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) when we have qualified as a “large accelerated filer,” which refers to when we (w) will have an aggregate worldwide market value of voting and non-voting shares of common equity securities held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (x) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for a period of at least 12 calendar months, (y) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act, and (z) no longer be eligible to use the requirements for “smaller reporting companies,” as defined in the Exchange Act, for our annual and quarterly reports.

Principal Executive Offices

Our principal executive offices are located at 5914 W. Courtyard Drive, Suite 100, Austin, Texas 78730, and our telephone number at that address is (512) 220-6350.

Our website address is www.brighamminerals.com. We expect to make our periodic reports and other information filed with or furnished to the United States Securities and Exchange Commission (the “SEC”) available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Risk Factors

An investment in our Class A common stock involves risks. You should carefully consider the following considerations, the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our Class A common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our Class A common stock and a loss of all or part of your investment.

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. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations.

• 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.

• Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.

18

• Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

• Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

• 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.

• 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.

• Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties. Unless we replace the oil, natural gas and NGLs produced from our properties, our results of operations and financial position could be adversely affected.

• We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.

• Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.

• The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

• The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

• Our estimated reserves are based on many assumptions that 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.

• Conservation measures, technological advances and general concern about the environmental impact of the production and use of fossil fuels could materially reduce demand for oil, natural gas and NGLs and adversely affect our results of operations and the trading market for shares of our Class A common stock.

• We rely on a few key individuals whose absence or loss could adversely affect our business.

• The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

• Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

• Our term loan facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

19

• The adoption of climate change legislation by Congress could result in increased operating costs for our operators and reduced demand for the oil, natural gas and NGLs that our operators produce.

• Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and free cash flow.

• Title to the properties in which we have an interest may be impaired by title defects.

• Loss of our or our operators’ information and computer systems, including as a result of cyber attacks, could materially and adversely affect our business.

Risks Related to this Offering and Our Class A Common Stock

• Brigham Minerals is a holding company. Brigham Minerals’ sole material asset after completion of this offering will be its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.

• The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

• We have identified and are in the process of remediating certain material weaknesses related to our risk assessment processes and certain controls related to revenues and certain recent transactions. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may cause current and potential stockholders to lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

• For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

20

The Offering

Issuer Brigham Minerals, Inc.

Class A common stock offered by us              shares (or                 shares, if the underwriters exercise in full their option to purchase additional shares)

Option to purchase additional shares We have granted the underwriters a 30-day option to purchase up to an aggregate of                  additional shares of our Class A common stock to the extent the underwriters sell more than                  shares of Class A common stock in this offering.

Class A common stock outstanding immediately after this offering              shares (or                  shares, if the underwriters exercise in full their option to purchase additional shares).

Class B common stock outstanding immediately after this offering             shares (                 shares if the underwriters’ option to purchase additional shares is exercised in full) or one share for each Brigham LLC Unit held by the Brigham Unit Holders immediately following this offering. Class B shares are non-economic. 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.

Voting power of Class A common stock after giving effect to this offering     % (or 100.0% if all outstanding Brigham LLC Units held by the Brigham Unit Holders were redeemed (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one-for-one basis). Upon completion of this offering, the Existing Owners will initially own                  shares of Class A common stock, representing approximately     % of the voting power of the Company.

Voting power of Class B common stock after giving effect to this offering     % (or 0% if all outstanding Brigham LLC Units held by the Brigham Unit Holders were redeemed (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one-for-one basis). Upon completion of this offering the Brigham Unit Holders will initially own                shares of Class B common stock, representing approximately     % of the voting power of the Company.

Voting rights Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote

21

or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. See “Description of Capital Stock.”

Use of proceeds We expect to receive approximately $                 million of net proceeds, based upon the assumed initial public offering price of $                 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $                 million.

We intend to contribute all of the net proceeds from this offering to Brigham LLC in exchange for Brigham LLC Units. Brigham LLC will use a portion of the net proceeds from this offering to partially repay the outstanding indebtedness under our term loan facility and the remaining net proceeds to fund future acquisitions of mineral and royalty interests. As of July 31, 2018, we had $150 million of outstanding borrowings under our term loan facility. Please read “Use of Proceeds.”

If the underwriters exercise their option to purchase additional shares of Class A common stock in full, the additional net proceeds to us would be approximately $                million (based on an assumed initial offering price of $                per share, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the underwriting discount. We intend to contribute all of the net proceeds therefrom to Brigham LLC in exchange for an additional number of Brigham LLC Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Brigham LLC will use any such net proceeds to fund future acquisitions of mineral and royalty interests. Please read “Use of Proceeds.”

Dividend policy We expect to pay dividends on our Class A common stock in amounts determined from time to time by our board of directors. However, the declaration and payment of any dividends will be at the sole discretion of our board of directors, which may change our dividend policy at any time. Future dividend levels will depend on the earnings of our subsidiaries, including Brigham LLC, their financial condition, cash requirements, regulatory restrictions, any restrictions in financing agreements (including our term loan facility) and other factors deemed relevant by the board. Please read “Dividend Policy.”

Redemption Rights of Brigham Unit Holders Under the Brigham LLC Agreement, each Brigham Unit Holder will, subject to certain limitations, have the right, pursuant to 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

22

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. Alternatively, upon the exercise of the Redemption Right, Brigham Minerals (instead of Brigham LLC) will have the right, pursuant to the Call Right, to 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. In connection with any redemption of Brigham LLC Units pursuant to the Redemption Right or acquisition pursuant our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Brigham LLC Agreement.”

Directed share program The underwriters have reserved for sale at the initial public offering price up to 5% of the Class A common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing Class A common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. The sales of shares pursuant to the directed share program will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, an underwriter of this offering. Please read “Underwriting.”

Listing and trading symbol We have applied to list our Class A common stock on the New York Stock Exchange (the “NYSE”) under the symbol “MNRL.”

Risk factors You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

The information above does not include                 shares of Class A common stock reserved for issuance pursuant to our LTIP (as defined in “Executive Compensation—2018 Long Term Incentive Plan”).

23

Summary Historical Financial Data

Brigham Minerals was formed in June 2018 and does not have historical financial operating results. The following table shows summary historical consolidated financial data, for the periods and as of the dates indicated, of our accounting predecessor, Brigham Resources, excluding the historical results and operations of Brigham Operating. The summary historical consolidated financial data of our predecessor as of and for the years ended December 31, 2016 and 2017 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary historical interim consolidated financial data of our predecessor as of June 30, 2018 and for the six months ended June 30, 2018 and 2017 were derived from the unaudited interim consolidated financial statements of our predecessor included elsewhere in this prospectus.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the historical financial statements of Brigham Resources included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

	Brigham Minerals Predecessor Historical
	Six Months Ended June 30,						Year Ended December 31,
	2018			2017			2017			2016
	(Restated)
	(In thousands, except per share data)
Statement of Operations Data:
Revenue:
Mineral and royalty revenue	$	26,386		$	12,032		$	30,066		$	14,046
Lease bonus and other revenue		4,586			8,092			10,842			7,187
Total revenue		30,972			20,124			40,908			21,233
Other operating income:
Gain on sale of oil and gas properties, net		—			94,558			94,551			—
Operating expense:
Gathering, transportation and marketing		2,007			668			1,754			820
Severance and ad valorem taxes		1,642			597			1,601			629
Depreciation, depletion and amortization		5,758			3,113			6,955			4,913
General and administrative		2,782			1,831			3,935			3,751
Total operating expense		12,189			6,209			14,245			10,113
Net income from operations		18,783			108,473			121,214			11,120
Other income (expense):
Loss on derivative instruments, net		(914	)		—			(121	)		—
Interest expense, net		(1,126	)		(150	)		(556	)		(298	)
Gain (Loss) on sale of equity securities		823			—			(4,222	)		—
Other income, net		10			151			305			476
Income before income taxes		17,576			108,474			116,620			11,298
Income tax expense		28			750			1,008			50
Net income	$	17,548		$	107,724		$	115,612		$	11,248

24

	Brigham Minerals Predecessor Historical
	Six Months Ended June 30,				Year Ended December 31,
	2018		2017		2017		2016
	(Restated)
	(In thousands, except per share data)
Pro Forma Information:
Pro forma net income(1)
Pro forma non-controlling interest(2)
Pro forma net income attributable to common stockholders(1)
Pro forma net income per share attributable to common stockholders(3)
Basic
Diluted
Pro forma weighted-average number of shares(3)
Basic
Diluted
Other Financial Data:
Adjusted EBITDA(4)		24,541		17,028		33,618		16,033
Adjusted EBITDA ex lease bonus(4)		19,955		8,936		22,776		8,846
	June 30, 2018				December 31,
					2017		2016
	(Restated)
Balance Sheet Data:
Cash and cash equivalents	$	1,590			$	6,886	$	33,960
Total assets		435,507				334,477		316,297
Long-term debt		70,000				27,000		15,000
Total liabilities		74,702				32,303		15,799
Total equity		360,805				302,174		300,498

(1) Pro forma net income reflects a pro forma income tax expense of $             million and $             million for the year ended December 31, 2017 and the six months ended June 30, 2018, respectively, of which $             million and $             million, respectively, is associated with the income tax effects of the corporate reorganization described under “—Corporate Reorganization” and this offering. Brigham Minerals is a corporation and is subject to U.S. federal income and State of Texas franchise tax. Our predecessor, Brigham Resources, was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net income in our historical financial statements does not reflect the tax expense we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods.

(2) Reflects the pro forma adjustment to non-controlling interest and net income attributable to common stockholders to reflect the ownership of Brigham LLC Units by each of the Existing Owners.

(3) Pro forma net income per share attributable to common stockholders and weighted average shares outstanding reflect the estimated number of shares of Class A common stock we expect to have outstanding upon the completion of our corporate reorganization described under “—Corporate Reorganization.”

(4) Please read “—Non-GAAP Financial Measures” below for the definitions of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to our most directly comparable financial measure, calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”).

25

Non-GAAP Financial Measure

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, interest expense, gain or loss on sale and distribution of equity securities, gain or loss on derivative instruments 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.     

	Brigham Minerals Predecessor Historical
	Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2018		2017		2018		2017		2017		2016
	(Restated)				(Restated)
	(in thousands)
Reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to net income:
Net income	$	9,351	$	5,024	$	17,548	$	107,724	$	115,612	$	11,248
Add:
Depreciation, depletion and amortization		3,213		1,551		5,758		3,113		6,955		4,913
Interest expense, net		652		79		1,126		150		556		298
Loss on sale and distribution of equity securities		—		—		—		—		4,222		—
Loss on commodity derivative instruments, net		555		—		914		—		121		—
Loss on sale of oil and gas properties		—		18		—		—		—		—
Income tax expense		12		99		28		750		1,008		50
Less:
Other income, net		6		75		10		151		305		476
Gain on sale of oil and gas properties		—		—		—		94,558		94,551		—
Gain on distribution of equity securities		—		—		823		—		—		—
Adjusted EBITDA	$	13,777	$	6,696	$	24,541	$	17,028	$	33,618	$	16,033
Less:
Lease bonus		2,367		1,294		4,586		8,092		10,842		7,187
Adjusted EBITDA ex lease bonus	$	11,410	$	5,402	$	19,955	$	8,936	$	22,776	$	8,846

26

Summary Reserve Data

The following table sets forth estimates of our net proved, probable and possible oil, natural gas and NGL reserves as of June 30, 2018 based on a reserve report prepared by CG&A. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Oil, Natural Gas and NGL Data—Proved, Probable and Possible Reserves,” “Business—Oil, Natural Gas and NGL Production Prices and Costs—Production and Price History,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and notes thereto included herein in evaluating the material presented below. The following table provides our estimated proved, probable and possible reserves as of June 30, 2018 using the provisions of the SEC rule regarding reserve estimation regarding a historical twelve-month pricing average applied prospectively.

	June 30, 2018(1)
Estimated proved developed reserves:
Oil (MBbls)		3,844
Natural gas (MMcf)		15,424
NGLs (MBbls)		1,427
Total (MBoe)		7,842
Estimated proved undeveloped reserves:
Oil (MBbls)		6,271
Natural gas (MMcf)		25,315
NGLs (MBbls)		2,826
Total (MBoe)		13,316
Estimated proved reserves:
Oil (MBbls)		10,115
Natural gas (MMcf)		40,739
NGLs (MBbls)		4,254
Total (MBoe)		21,159
Estimated probable reserves:
Oil (MBbls)(2)		13,478
Natural gas (MMcf)(2)		56,506
NGLs (MBbls)(2)		6,716
Total (MBoe)(2)		29,612
Estimated possible reserves:
Oil (MBbls)(2)		8,861
Natural gas (MMcf)(2)		22,803
NGLs (MBbls)(2)		3,218
Total (MBoe)(2)		15,880
Oil—WTI posted price per Bbl	$	57.52
Natural gas—Henry Hub spot price per Mcf	$	2.91

(1) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $57.52 per barrel as of June 30, 2018 was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 24% to 43% of the WTI posted price. For gas volumes, the average Henry Hub spot price of $2.91 per MMBtu as of June 30, 2018 was adjusted for energy content, transportation fees and a regional price differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $54.50 per barrel of oil, $21.29 per barrel of NGL and $2.44 per Mcf of gas as of June 30, 2018.

(2) All of our estimated probable and possible reserves are classified as undeveloped.

27

RISK FACTORS

Investing in our Class A common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

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. A substantial or extended decline in commodity prices 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 prevailing prices for oil, natural gas and NGLs. 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:

• 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;

• 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”) 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;

• 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

28

price for West Texas Intermediary (“WTI”) light sweet crude oil has ranged from a low of $26.19 per Bbl in February 2016 to a high of $110.62 per Bbl in September 2013, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014.

Any substantial decline in the price of oil, natural gas and NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and free cash flow. In addition, 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 our properties. This may result in our having to make substantial downward adjustments to our estimated proved, probable or possible reserves, which could negatively impact our borrowing base and our ability to fund our operations. 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. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil, natural gas or NGLs in commercially paying quantities.

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.

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 year ended December 31, 2017, we received revenue from over 100 operators, with approximately 50% coming from the top ten operators on our properties. 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. 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;

• the ability of our operators to access capital;

• prevailing commodity prices;

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

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

• approval of other participants in drilling wells;

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

• the selection of technology;

29

• 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 us.

Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.

We depend partly on acquisitions to grow our reserves, production and free cash flow. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil, natural gas and NGL prices and their applicable differentials;

• development plans;

• the operating costs our operators would incur to develop and operate the properties; and

• potential environmental and other liabilities that operators of the properties may incur.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing. In addition, these acquisitions may be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and free cash flow. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and free cash flow.

30

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about estimated proved, probable and possible reserves, future production, prices, revenues, capital expenditures, the operating expenses and costs our operators would incur to develop the minerals;

• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

• mistaken assumptions about the overall cost of equity or debt;

• our ability to obtain satisfactory title to the assets we acquire;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

• the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, oil, natural gas and NGL prices, costs, drilling results and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation and free cash flow.

Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data. As a result, our operators may have reached different conclusions about the potential drilling locations on our properties, and our operators control the ultimate decision as to where and when a well is drilled.

31

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.

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. 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.

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 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 term loan facility. We cannot assure you that we will be able to access external capital on terms favorable to us or at all. 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.

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 future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties. Unless we replace the oil, natural gas and NGLs produced from our properties, our results of operations and financial position could be adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil, natural gas and NGL reserves and our operators’ production thereof and our free cash flow are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of our properties at economically acceptable terms. Aside from acquisitions, we have little to no control over the exploration and development of our properties. If we are not able to replace or grow our oil, natural gas and NGL reserves, our business, financial condition and results of operations would be adversely affected.

32

We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.

As of June 30, 2018, only 7,842 MBoe of our total estimated reserves were proved developed reserves. The remaining 13,316 MBoe, 29,612 MBoe and 15,880 MBoe of our total estimated reserves were PUDs, probable undeveloped reserves and possible undeveloped reserves, respectively, and may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. The reserve data included in the reserve reports of CG&A assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.

Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and free cash flow may be adversely affected.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.

The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities,

33

and the shipment of our or our operators’ oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and free cash flow. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil, natural gas and NGL production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Our derivative activities could result in financial losses and reduce earnings.

From time to time in the past we have used, and in the future we may use, derivative instruments for a portion of our future oil, natural gas and NGL production, including fixed price swaps, collars and basis swaps, to mitigate the risk and resulting impact of commodity price volatility. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural gas and NGL prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract. Further, our hedging activities are not likely to mitigate the entire exposure of our operations to commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

Our estimated reserves are based on many assumptions that 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 June 30, 2018 and December 31, 2017 and 2016 were prepared by CG&A, which conducted a detailed review of all of our properties for the period covered by its reserve reports 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, in connection with the restatement of our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018 discussed elsewhere in this prospectus, we also elected to revise our previously reported reserves as of June 30, 2018 in order to properly account for our ownership interests in certain of our properties where there were title discrepancies and calculation errors within our internal reserves tracking software. In addition, certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs may prove incorrect. 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

34

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 (the “FASB”), we base the estimated discounted future net cash flows from our proved reserves on the 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.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators. Although we believe that our approach in making such determinations is conservative, the accuracy of any such determination is inherently uncertain and subject to a number of assumptions and factors outside of our control, including but not limited to those described under “—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.” Any significant variance between our estimates and the actual drilling schedules of our operators may require us to write down our proved undeveloped reserves.

If oil, natural gas and NGL prices decline to near or below the low levels experienced in 2015 and 2016, 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. 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

35

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. We did not record any non-cash impairment charges for our oil, natural gas and NGL properties in 2017 or 2016. 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.

Conservation measures, technological advances and general concern about the environmental impact of the production and use of fossil fuels could materially reduce demand for oil, natural gas and NGLs and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy-generation devices could reduce demand for oil, natural gas and NGLs. The impact of the changing demand for oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and free cash flow. It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock.

We rely on a few key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of

36

our undeveloped acreage could decline, and our results of operations and free cash flow could be adversely affected.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, our ORRIs may be lost if the underlying acreage is not drilled before the expiration of the applicable lease or if the lease otherwise terminates.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.

Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or terminates, all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also terminate. Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect the growth of our financial condition, results of operations and free cash flow.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition and results of operations.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our shareholders that wells drilled by the operators of our properties will be productive. Drilling for oil, natural gas and NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil, natural gas or NGLs to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil, natural gas or NGL is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

• unusual or unexpected geological formations;

• loss of drilling fluid circulation;

• title problems;

• facility or equipment malfunctions;

• unexpected operational events;

• shortages or delivery delays of equipment and services;

• compliance with environmental and other governmental requirements; and

• adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and free cash flow may be materially adversely affected.

37

Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

Our operators’ operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil, natural gas and NGLs. In addition, the production, handling, storage and transportation of oil, natural gas and NGLs, as well as the remediation, emission and disposal of oil, natural gas and NGL wastes, by-products thereof and other substances and materials produced or used in connection with oil, natural gas and NGL operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control and waste management.

Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including:

• provisions related to the unitization or pooling of the oil and natural gas properties;

• the establishment of maximum rates of production from wells;

• the spacing of wells;

• the plugging and abandonment of wells; and

• the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party oil, natural gas and NGL transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral and royalty interests.

Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production and may ultimately impact our operators’ ability and willingness to develop our properties.

38

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the U.S. Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the U.S. Environmental Protection Agency (“EPA”) has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued guidance covering such activities. In addition, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we own mineral or royalty interests, our operators may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and that could result in added delays or curtailment in our operators’ pursuit of exploration, development or production activities, which would in turn reduce the oil, natural gas and NGLs produced from our properties.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Furthermore, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would allow revisions to the state constitution in a manner that would make such activities in the state more difficult in the future.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of oil, natural gas and NGLs, including from the developing shale plays, or

39

could make it more difficult for our operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in our operators’ completion of new oil and natural gas wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, which could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.

In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in.

The adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Restrictions on the ability of our operators to obtain water may have an adverse effect on our financial condition, results of operations and free cash flow.

Water is an essential component of deep shale oil, natural gas and NGL production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country, and in particular Texas, have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If our operators are unable to obtain water to use in their operations from local sources, or if our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil, natural gas and NGLs from our properties, which could have an adverse effect on our financial condition, results of operations and free cash flow.

Our term loan facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

As of July 31, 2018, we had outstanding borrowings of $150 million under our term loan facility. The operating and financial restrictions and covenants in our term loan facility restrict, and any future financing

40

agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends. Our term loan facility restricts, and any future financing agreements likely will restrict, our ability to, among other things:

• incur indebtedness;

• issue certain equity securities, including preferred equity securities;

• incur certain liens or permit them to exist;

• engage in certain fundamental changes, including mergers or consolidations;

• make certain investments, loans, advances, guarantees and acquisitions;

• sell or transfer assets;

• enter into sale and leaseback transactions;

• pay dividends to or redeem or repurchase shares from our shareholders;

• make certain payments of junior indebtedness;

• enter into transactions with our affiliates;

• enter into certain restrictive agreements; and

• enter into swap agreements and hedging arrangements.

Our term loan facility restricts our ability to pay dividends to our shareholders or to repurchase shares of our Class A common stock. We also are required to comply with certain financial and collateral coverage covenants and ratios under our term loan facility, which upon the consummation of this offering will include maintaining (i) a total net leverage ratio not to exceed 4.00 to 1.00 as of the last day of any fiscal quarter and (ii) an asset coverage ratio of not less than 1.75 to 1.00. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. If we violate any of the restrictions, covenants, ratios or tests in our term loan facility, a significant portion of our indebtedness may become immediately due and payable, our ability to pay dividends to our shareholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our term loan facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our term loan facility, the lenders can seek to foreclose on our assets.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and future indebtedness could have important consequences to us, including:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;

• covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our access to the capital markets may be limited;

• our borrowing costs may increase;

• we will need a substantial portion of our free cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payment of dividends to our shareholders; and

41

• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

The adoption of climate change legislation by Congress could result in increased operating costs for our operators and reduced demand for the oil, natural gas and NGLs that our operators produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the U.S. Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operators’ operations. The EPA has expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells.

Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years and reconsider the entirety of the 2016 standards; the EPA has not yet published a final rule and, as a result, the 2016 standards are currently in effect but future implementation of the 2016 standards is uncertain at this time. Additionally, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the U.S. in April 2016 and entered in force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. Moreover, in August 2017, the U.S. State Department informed the United Nations of the intent of the U.S. to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or separately negotiated agreement are unclear at this time.

42

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition and results of operations. Moreover, recent activism directed at shifting funds away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our operators’ operations and the production on our properties.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our operators’ ability to conduct drilling activities.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our operators operate, our operators’ abilities to conduct or expand operations could be limited, or our operators could be forced to incur material additional costs. Moreover, our operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

In addition, as a result of one or more settlements approved by the U.S. Fish & Wildlife Service (the “FWS”), the agency is required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The designation of previously unidentified endangered or threatened species could cause our operators’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands.

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and free cash flow.

The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil, natural gas and NGLs, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of oil, natural gas, NGLs and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGL market prices. Our operators’ larger

43

competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. In addition, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transaction in a highly competitive environment. Because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to the properties in which we have an interest may be impaired by title defects.

We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our royalty and mineral interests. In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and free cash flow. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects in properties in which we hold an interest, we may suffer a financial loss.

Loss of our or our operators’ information and computer systems, including as a result of cyber attacks, could materially and adversely affect our business.

We and our operators rely on electronic systems and networks to control and manage our respective businesses. If any of such programs or systems were to fail for any reason, including as a result of a cyber attacks, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences could be significant, including loss of communication links and inability to automatically process commercial transaction or engage in similar automated or computerized business activities. Although we have multiple layers of security to mitigate risks of cyber attacks, cyber attacks on business have escalated in recent years. Moreover, our operators are becoming increasingly dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. If our operators become the target of cyberattacks of information security breaches, their business operations may be substantially disrupted, which could have an adverse effect on our results of operations.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil, natural gas and NGLs, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil, natural gas and NGL related facilities could be direct targets of terrorist attacks, and, if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and free cash flow.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to economic

44

uncertainty and diminished expectations for the global economy. 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. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, 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.

Risks Related to this Offering and Our Class A Common Stock

Brigham Minerals is a holding company. Brigham Minerals’ sole material asset after completion of this offering will be its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.

Brigham Minerals is a holding company and will have no material assets other than its equity interest in Brigham LLC. Please see “Corporate Reorganization.” Brigham Minerals has no independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) generally pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non pro rata distributions to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham LLC, we intend to cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow us to fund dividends to our stockholders in accordance with our dividend policy, to the extent our board of directors declares such dividends. Therefore, although we expect to pay dividends on our Class A common stock in amounts determined from time to time by our board of directors, our ability to do so may be limited to the extent Brigham LLC and its subsidiaries are limited in their ability to make these and other distributions to us, including due to the restrictions under our term loan facility. To the extent that we need funds and Brigham LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

• institute a more comprehensive compliance function;

• comply with rules promulgated by the NYSE;

• continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

• establish new internal policies, such as those relating to insider trading; and

• involve and retain to a greater degree outside counsel and accountants in the above activities.

45

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2019, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until 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. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2023. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We have identified and are in the process of remediating certain material weaknesses related to our risk assessment processes and certain controls related to revenues and certain recent transactions. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may cause current and potential stockholders to lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Our internal control over financial reporting does not currently meet all the standards contemplated by Section 404 of the Sarbanes-Oxley Act that we will eventually be required to meet. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance at the time required, we may be unable to report on a timely basis, which could subject us to adverse regulatory consequences, including sanctions by the SEC, or result in violations of applicable stock exchange listing rules.

In connection with the preparation and review of our unaudited consolidated financial statements for the nine months ended September 30, 2018, our management identified certain material weaknesses related to our risk assessment processes and certain controls related to revenues and certain recent transactions. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. After identifying such material weaknesses, which resulted in errors in our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018, we reviewed our audited financial statements for the years ended December 31, 2017 and 2016 for additional potential accrual and presentation errors, which resulted in an immaterial correction of the presentation of gains and losses on sales of assets to include such gains and losses in other operating income for all periods presented. We are in the process of remediating the material weaknesses identified. As an emerging growth company we have not been required to assess the effectiveness of our internal controls and additional material weaknesses may exist.

Although management is working to remediate the material weaknesses, there is no assurance that its changes will remediate the identified material weaknesses or that the controls will prevent or detect future material weaknesses. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company, and if we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Control Procedures—Material Weakness and Remediation.”

46

The initial public offering price of our Class A common stock may not be indicative of the market price of our Class A common stock after this offering. In addition, an active, liquid and orderly trading market for our Class A common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our Class A common stock was not traded on any market. An active, liquid and orderly trading market for our Class A common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our Class A common stock after this offering. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

• our operating and financial performance, including reserve estimates;

• quarterly variations in our financial and operating results;

• the public reaction to our press releases, our other public announcements and our filings with the SEC;

• strategic actions by our competitors;

• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

• speculation in the press or investment community;

• the failure of research analysts to cover our Class A common stock;

• sales of our Class A common stock by us or our stockholders or the perception that such sales may occur;

• changes in accounting principles, policies, guidance, interpretations or standards;

• additions or departures of key management personnel;

• actions by our stockholders;

• general market conditions, including fluctuations in commodity prices;

• domestic and international economic, legal and regulatory factors unrelated to our performance; and

• the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Our Sponsors will have the ability to direct the voting of a majority of the voting power of our common stock, and their interests may conflict with those of our other stockholders.

Holders of shares of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. Upon completion of this offering, our Sponsors will beneficially own, on a combined basis, approximately     % of our outstanding shares of Class A common stock (or approximately     % if the underwriters exercise their option to purchase additional shares in full) and     % of our shares of Class B

47

common stock, representing     % of our combined economic interest and voting power (or approximately     % if the underwriters exercise their option to purchase additional shares in full). As a result, on a combined basis, our Sponsors will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of our Sponsors with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders.

Given this concentrated ownership, our Sponsors would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of our Sponsors. These directors’ duties as employees of our Sponsors may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. In addition, the existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Our Sponsors’ concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including Warburg Pincus-, Yorktown- and Pine Brook-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, two of our directors (Messrs. Holland and Levy) are senior investment professionals of Warburg Pincus, one of our directors (Mr. Keenan) is a Managing Member of Yorktown and one of our directors (Mr. Stoneburner) is a Managing Director of Pine Brook, all of which are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. In addition, Mr. Brigham, our executive chairman, is involved with certain other entities involved in the oil and gas industry, including Brigham Operating, Atlas Permian Water, Atlas Permian Sand, Brigham Development and Anthem Ventures. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that our Sponsors and their affiliates (including portfolio investments of our Sponsors and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our Sponsors or their respective affiliates. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:

• permit our Sponsors and their affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

48

• provide that if our Sponsors or their affiliates or any director or officer of one of our affiliates, our Sponsors or their affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our Sponsors or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our Sponsors and their affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Sponsors and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock—Corporate Opportunity.”

Each of our Sponsors is an established participant in the oil and natural gas industry and has resources greater than ours, which may make it more difficult for us to compete with our Sponsors with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and our Sponsors, on the other hand, will be resolved in our favor. As a result, competition from our Sponsors and their affiliates could adversely impact our results of operations.

A significant reduction by our Sponsors of their ownership interests in us could adversely affect us.

We believe that our Sponsor’s ownership interests in us provide them with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities following the completion of this offering, our Sponsors will not be subject to any obligation to maintain their ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us. If our Sponsors sell all or a substantial portion of their respective ownership interests in us, they may have less incentive to assist in our success and their affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our business, financial condition and results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, some of which will not apply until our Sponsors and their respective affiliates no longer collectively beneficially own (or otherwise have the right to vote or direct the vote of) more than 50% of our

49

outstanding shares of common stock, which event we refer to as the “Trigger Event.” Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders;

• provide that the authorized number of directors constituting our board of directors may be changed only by resolution of the board of directors;

• provide that, after the Trigger Event, all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of our preferred stock, be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares);

• provide that our bylaws can be amended by the board of directors;

• provide that, after the Trigger Event, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of our preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

• provide that, after the Trigger Event, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of not less than 66 2/3% of our then outstanding shares of common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding shares of common stock);

• provide that, after the Trigger Event, special meetings of our stockholders may only be called by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote (prior to such time, a special meeting may also be called at the request of our stockholders holding a majority of the then outstanding shares entitled to vote generally in the election of directors voting together as a single class);

• provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our preferred stock, if any;

• provide that the affirmative vote of the holders of not less than 66 2/3% in voting power of all then outstanding shares of common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office, and such removal may only be for “cause”; and

• prohibit cumulative voting on all matters.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our amended and restated

50

bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $                per share.

Based on an assumed initial public offering price of $                per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of shares of our Class A common stock in this offering will experience an immediate and substantial dilution of $                per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2017 after giving effect to this offering would be $                per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

Our ability to pay dividends to our stockholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.

After this offering, Brigham Minerals will be a holding company and will have no material assets other than its ownership of Brigham LLC Units, and Brigham Minerals will not have any independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) generally pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non-pro rata distributions to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham LLC, Brigham Minerals intends to cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow it to fund dividends to its stockholders in accordance with its dividend policy, to the extent its board of directors declares such dividends. Brigham LLC is a distinct legal entity and may be subject to legal or contractual restrictions that, under certain circumstances, may limit Brigham Minerals ability to obtain cash from it. If Brigham LLC is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our free cash flow and financial position and our ability to fund any dividends.

Although we expect to pay dividends on our Class A common stock, our board of directors will take into account general economic and business conditions, including our financial condition and results of operations, capital requirements, contractual restrictions, including restrictions and covenants contained in our debt agreements, business prospects and other factors that our board of directors considers relevant in determining whether, and in what amounts, to pay such dividends. In addition, the credit agreement governing our term loan facility limits the amount of distributions that Brigham LLC can make to us and the purposes for which distributions could be made. Accordingly, we may not be able to pay dividends even if our board of directors would otherwise deem it appropriate. See “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity” and “Description of Capital Stock.”

51

In certain circumstances, Brigham LLC will be required to make tax distributions to the Brigham Unit Holders, including Brigham Minerals, and such tax distributions may be substantial. To the extent Brigham Minerals receives tax distributions in excess of its actual tax liabilities and retains such excess cash, the Existing Owners would benefit from such accumulated cash balances if they exercise their Redemption Right.

Pursuant to the Brigham LLC Agreement, to the extent Brigham LLC has available cash (taking into account existing and projected capital expenditures), Brigham LLC is required to make generally pro rata distributions (which we refer to as “tax distributions”), to all its unitholders, including Brigham Minerals, in an amount generally intended to allow the Brigham Unit Holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that tax distributions will be made sufficient to allow Brigham Minerals to satisfy its actual tax liabilities. The amount of such tax distributions will be determined based on certain assumptions, including an assumed individual income tax rate, and will be calculated after taking into account other distributions (including other tax distributions) made by Brigham LLC. Because tax distributions will be made pro rata based on ownership and due to, among other items, differences between the tax rates applicable to Brigham Minerals and the assumed individual income tax rate used in the calculation and requirements under the applicable tax rules that Brigham LLC’s net taxable income be allocated disproportionately to its unitholders in certain circumstances, tax distributions may significantly exceed the actual tax liability for many of the Brigham Unit Holders, including Brigham Minerals. If Brigham Minerals retains the excess cash it receives, the Existing Owners would benefit from any value attributable to such accumulated cash balances as a result of their exercise of the Redemption Right. However, we expect to use such accumulated cash balances to pay dividends in respect of our Class A common stock or to take other steps to eliminate any material cash balances. In addition, the tax distributions Brigham LLC will be required to make may be substantial and may exceed the tax liabilities that would be owed by a similarly situated corporate taxpayer. Funds used by Brigham LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business, except to the extent Brigham Minerals uses the excess cash it receives to reinvest in Brigham LLC for additional units.

The U.S. federal income tax treatment of distributions on our Class A common stock to a holder will depend upon our tax attributes and the holder’s tax basis in our stock, which are not necessarily predictable and can change over time.

Distributions of cash or property on our Class A common stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our Class A common stock and thereafter as capital gain from the sale or exchange of such common stock. Also, if any holder sells our Class A common stock, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A common stock.

To the extent that the amount of our distributions is treated as a non-taxable return of capital as described above, such distribution will reduce a holder’s tax basis in the Class A common stock. Consequently, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A common stock or subsequent distributions with respect to such stock. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a distribution on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess distribution.

52

Prospective investors in our Class A common stock are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.

Future sales of shares of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Certain of our Existing Owners own shares of our Class A common stock and, subject to certain limitations and exceptions, the Existing Owners that hold Brigham LLC Units may require Brigham LLC to redeem their Brigham LLC Units for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions), and our Existing Owners may sell any of such shares of Class A common stock. Additionally, after the expiration or waiver of the lock-up provision contained in the underwriting agreement entered into in connection with this offering, we may sell additional shares of Class A common stock in subsequent public offerings or may issue additional shares of Class A common stock or convertible securities. After the completion of this offering, we will have outstanding                  shares of Class A common stock and                 shares of Class B common stock. This number includes                  shares of Class A common stock that we are selling in this offering and                 shares of Class A common stock that we may sell in this offering if the underwriters exercise their option to purchase additional shares in full, which shares may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, the Existing Owners will own                 shares of our Class A common stock and                 shares of Class B common stock, representing approximately     % (or     % if the underwriters’ option to purchase additional shares is exercised in full) of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting,” but may be sold into the market in the future. The Existing Owners will be party to a registration rights agreement, which will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. See “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of                  shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

The underwriters of this offering may release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, all of our directors and executive officers and the Existing Owners have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A common stock for a period of 180 days following the date of this prospectus. Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the

53

Class A common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

Our organizational structure confers certain benefits upon the Existing Owners that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Existing Owners.

Our organizational structure confers certain benefits upon the Existing Owners that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Existing Owners. Brigham Minerals will be a holding company and will have no material assets other than its ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Existing Owners will be entitled to receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Existing Owners on a per unit basis. This and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation will authorize our board of directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our Class A common stock.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our Class A common stock to be less attractive as a result, there may be a less active trading market for our Class A common stock and our stock price may be more volatile.

54

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act, our financial statements may not be comparable to those of other public companies.

Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. Accordingly, our financial statements may not be comparable to companies that comply with public company effective dates, and our stockholders and potential investors may have difficulty in analyzing our operating results by comparing us to such companies.

55

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact, included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, 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 prospectus.

The following important factors, in addition to those discussed elsewhere in this prospectus, 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 strategies;

• the effect of changes in commodity prices;

• the level of production on our properties;

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

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

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

• the availability of pipeline capacity and transportation facilities;

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

• the impact of derivative instruments;

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

• the overall supply and demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;

• competition from others in the energy industry;

• uncertainty in whether development projects will be pursued;

• 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 and natural gas reserves;

• our ability to identify, complete and integrate acquisitions;

• title defects in the properties in which we invest;

• the cost of inflation;

• technological advances; and

• general economic, business or industry conditions.

56

Should one or more of the risks or uncertainties described in this prospectus 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 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 and natural gas that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this prospectus 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 prospectus.

57

USE OF PROCEEDS

We expect to receive approximately $                million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the Class A common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to contribute all of the net proceeds from this offering to Brigham LLC in exchange for Brigham LLC Units. Brigham LLC will use the net proceeds to partially repay the outstanding indebtedness under our term loan facility and the remaining net proceeds to fund our future mineral and royalty acquisitions. The following table illustrates our anticipated use of the net proceeds from this offering:

Sources of Funds		Use of Funds
(In millions)
Net proceeds from this offering	$	Repayment of our term loan facility	$
		Funding of our future mineral and royalty acquisitions
Total sources of funds	$	Total uses of funds	$

As of July 31, 2018, we had $150 million of borrowings outstanding under our term loan facility. Our term loan facility matures on July 27, 2024 and bears interest calculated under the terms of our credit agreement at either a fixed rate equal to the base rate plus 4.50% or an adjusted LIBOR rate (subject to a 1.00% floor) plus 5.50%, at our election. Upon the consummation of this offering, each of the foregoing margins will decrease by 0.50% if at the end of the most recently completed fiscal quarter our total net leverage ratio (as defined in the credit agreement governing our term loan facility) is less than or equal to 2.00 to 1.00. At July 31, 2018, the weighted average interest rate on borrowings under our term loan facility was 7.58%. The outstanding borrowings under our term loan facility were incurred to repay the outstanding debt under our prior revolving credit facility and to fund mineral and royalty acquisitions.

A $1.00 increase or decrease in the assumed initial public offering price of $                per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $                million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds to fund additional mineral and royalty acquisitions in the future. If the proceeds decrease due to a lower initial public offering price, then we would first reduce by a corresponding amount the net proceeds directed to acquisitions and then, if necessary, the net proceeds directed to repay outstanding borrowings under our term loan facility.

To the extent the underwriters’ option to purchase additional shares is exercised, we intend to contribute all of the net proceeds therefrom to Brigham LLC in exchange for an additional number of Brigham LLC Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Brigham LLC will use any such net proceeds to fund future acquisitions of mineral and royalty interests.

58

DIVIDEND POLICY

We expect to pay dividends on our Class A common stock in amounts determined from time to time by our board of directors. The declaration and payment of any dividends by us will be at the sole discretion of our board of directors, which may change our dividend policy at any time. Our board of directors will take into account:

• general economic and business conditions;

• our financial condition and operating results;

• our free cash flow and current and anticipated cash needs;

• our capital requirements;

• legal, tax, regulatory and contractual (including under our term loan facility) restrictions and implications on the payment of dividends by us to our stockholders or by our subsidiaries (including Brigham LLC) to us; and

• such other factors as our board of directors may deem relevant.

We will be a holding company and will have no material assets other than our ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Existing Owners will be entitled to receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Existing Owners on a per unit basis.

Assuming Brigham LLC makes distributions to us and the Existing Owners in any given year, we expect to pay dividends in respect of our Class A common stock out of the portion, if any, of such distributions remaining after our payment of taxes and our expenses (any such portion, an “excess distribution”). However, because our board of directors may determine to pay or not pay dividends in respect of shares of our Class A common stock based on the factors described above, our holders of Class A common stock may not necessarily receive dividend distributions relating to excess distributions, even if Brigham LLC makes such distributions to us.

59

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2018:

• on an actual basis for our predecessor; and

• on an as adjusted basis to give effect to the sale of shares of our Class A common stock in this offering at an assumed initial offering price of $                per share (which is the midpoint of the range set forth on the cover of this prospectus) and the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds” and the financial statements and accompanying notes included elsewhere in this prospectus.

	As of June 30, 2018
	Predecessor(1)		As Adjusted(2)
	(In thousands, except number of shares and par value)
Cash and cash equivalents	$	1,590	$
Long-term debt, including current maturities:
Revolving credit facility(3)		70,000
Total long-term debt	$	70,000	$
Equity:
Members’ contributed capital		207,795
Class A common stock—$0.01 par value; no shares authorized, issued or outstanding, actual;              shares authorized,              shares issued and outstanding, pro forma		—
Class B common stock—$0.01 par value; no shares authorized, issued or outstanding, actual;              shares authorized,              shares issued and outstanding, pro forma		—
Additional paid-in capital		—
Accumulated other comprehensive income
Accumulated earnings		153,010
Total equity	$	360,805	$
Total capitalization	$	430,805	$

(1) Brigham Minerals was incorporated in June 2018. The data in this table has been derived from the historical consolidated financial statements included in this prospectus which pertain to the assets, liabilities, revenues and expenses of our accounting predecessor.

(2) A $1.00 increase (decrease) in the assumed initial public offering price of $                per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $                million, $                million and $                million, respectively, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $                per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $                million, $                million and $                million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

60

(3) On July 27, 2018, we entered into our term loan facility, which provides for an initial term loan of $125 million, a delayed draw term loan of $75 million and a revolving credit facility of $10 million for general corporate purposes. We used the proceeds of our term loan facility to repay the outstanding balance of $70 million under our prior revolving credit facility and to fund mineral and royalty acquisitions. As of July 31, 2018, we had $150 million of outstanding borrowings under our term loan facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity—Our Term Loan Facility.” After giving effect to the sale of shares of our Class A common stock in this offering and the application of the anticipated net proceeds of this offering, we expect to have $                million of available borrowing capacity under our term loan facility.

61

DILUTION

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of our Class A common stock for accounting purposes. Our net tangible book value as of June 30, 2018, after giving pro forma effect to our corporate reorganization, was approximately $                million, or $                per share of Class A common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering including giving effect to the corporate reorganization. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of June 30, 2018 would have been approximately $                million, or $                per share. This represents an immediate increase in the net tangible book value of $                 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $                 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our Class B common stock has been cancelled in connection with a redemption of Brigham LLC Units for Class A common stock):

Initial public offering price per share		$
Pro forma net tangible book value per share as of June 30, 2018 (after giving effect to the corporate reorganization)	$
Increase per share attributable to new investors in the offering	$
As adjusted pro forma net tangible book value per share (after giving effect to the corporate reorganization and this offering)
Dilution in pro forma net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $                per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $                and increase (decrease) the dilution to new investors in this offering by $                per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an adjusted pro forma basis as of June 30, 2018, the total number of shares of Class A common stock owned by existing stockholders (assuming that 100% of our Class B common stock has been cancelled in connection with a redemption of Brigham LLC Units for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $                , calculated before deduction of estimated underwriting discounts and commissions.

	Shares Purchased				Total Consideration				Average Price Per Share
	Number	Percent			Amount	Percent
	(in millions)
Existing stockholders					$			%	$
New investors					$			%	$
Total			100	%	$		100	%	$

62

The data in the table excludes                  shares of Class A common stock initially reserved for issuance under our equity incentive plan.

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to                 , or approximately     % of the total number of shares of Class A common stock.

63

SELECTED HISTORICAL FINANCIAL DATA

Brigham Minerals was formed in June 2018 and does not have historical financial operating results. The following table shows selected historical consolidated financial data, for the periods and as of the dates indicated, of our accounting predecessor, Brigham Resources, excluding the historical results and operations of Brigham Operating. The selected historical consolidated financial data of our predecessor as of and for the years ended December 31, 2016 and 2017 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected historical interim consolidated financial data of our predecessor as of June 30, 2018 and for the six months ended June 30, 2018 and 2017 were derived from the unaudited interim consolidated financial statements of our predecessor included elsewhere in this prospectus.

For a detailed discussion of the selected historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the interim historical financial statements of Brigham Resources included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

	Brigham Minerals Predecessor Historical
	Six Months Ended June 30,						Year Ended December 31,
	2018			2017			2017			2016
	(Restated)
	(In thousands, except per share data)
Statement of Operations Data:
Revenue:
Mineral and royalty revenue	$	26,386		$	12,032		$	30,066		$	14,046
Lease bonus and other revenue		4,586			8,092			10,842			7,187
Total revenue		30,972			20,124			40,908			21,233
Other operating income:
Gain on sale of oil and gas properties, net		—			94,558			94,551			—
Operating expense:
Gathering, transportation and marketing		2,007			668			1,754			820
Severance and ad valorem taxes		1,642			597			1,601			629
Depreciation, depletion and amortization		5,758			3,113			6,955			4,913
General and administrative		2,782			1,831			3,935			3,751
Total operating expense		12,189			6,209			14,245			10,113
Net income from operations		18,783			108,473			121,214			11,120
Other income (expense):
Loss on derivative instruments, net		(914	)		—			(121	)		—
Interest expense, net		(1,126	)		(150	)		(556	)		(298	)
Gain (loss) on sale of equity securities		823			—			(4,222	)		—
Other income, net		10			151			305			476
Income before income taxes		17,576			108,474			116,620			11,298
Income tax expense		28			750			1,008			50
Net income	$	17,548		$	107,724		$	115,612		$	11,248
Pro Forma Information:
Pro forma net income(1)
Pro forma non-controlling interest(2)
Pro forma net income attributable to common stockholders(1)
Pro forma net income per share attributable to common stockholders(3)
Basic
Diluted
Pro forma weighted-average number of shares(3)
Basic
Diluted

64

	Brigham Minerals Predecessor Historical
	Six Months Ended June 30,				Year Ended December 31,
	2018		2017		2017		2016
	(Restated)
	(In thousands, except per share data)
Other Financial Data:
Adjusted EBITDA(4)		24,541		17,028		33,618		16,033
Adjusted EBITDA ex lease bonus(4)		19,955		8,936		22,776		8,846
	June 30, 2018				December 31,
					2017		2016
Balance Sheet Data:
Cash and cash equivalents	$	1,590			$	6,886	$	33,960
Total assets		435,507				334,477		316,297
Credit facilities		70,000				27,000		15,000
Total liabilities		74,702				32,303		15,799
Total equity		360,805				302,174		300,498

(1) Pro forma net income reflects a pro forma income tax expense of $         million for the year ended December 31, 2017, of which $         million is associated with the income tax effects of the corporate reorganization described under “—Corporate Reorganization” and this offering. Brigham Minerals is a corporation and is subject to U.S. federal income and State of Texas franchise tax. Our predecessor, Brigham Resources, was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net income in our historical financial statements does not reflect the tax expense we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods.

(2) Reflects a pro forma adjustment to non-controlling interest and net income attributable to common stockholders to reflect the ownership of Brigham LLC Units by each of the Existing Owners.

(3) Pro forma net income per share attributable to common stockholders and weighted average shares outstanding reflect the estimated number of shares of Class A common stock we expect to have outstanding upon the completion of our corporate reorganization described under “Corporate Reorganization.”

(4) Please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measures” below for the definitions of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to our most directly comparable financial measure, calculated and presented in accordance with GAAP.

65

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. 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, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, 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.

Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of our predecessor, Brigham Resources, excluding the historical results and operations of Brigham Operating, and does not give effect to the transactions described in “Corporate Reorganization.”

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 basins across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our shareholders by both capturing growth in free cash flow from the continued development of our existing portfolio of over 10,187 undeveloped horizontal drilling locations unburdened by development capital expenditures or lease operating expenses, as well as leveraging our highly experienced technical evaluation team to continue to execute upon our scalable business model of sourcing, methodically evaluating and integrating accretive minerals acquisitions in the core of top-tier, liquids-rich resource plays.

As of June 30, 2018, we owned 61,219 net royalty acres across 37 counties within four of the most highly economic, liquids-rich basins in the continental United States, including the Permian Basin in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota. On a pro forma basis giving effect to our portfolio of 61,219 net royalty acres at June 30, 2018 as if we had owned it since January 1, 2013, we estimate that the production volumes net to our interests would have grown at an approximate 53% compound annual growth rate, or CAGR, from the beginning of 2013 through June 30, 2018, despite crude oil prices decreasing substantially during that same time period. As of June 30, 2018, we received royalty revenue from roughly 2,700 gross horizontal wells and believe we will see continued growth in production, revenue and free cash flow from 586 DUCs, an average of 27 horizontal rigs running on our interests over the last year and 751 horizontal drilling permits across our mineral and royalty interests (excluding Laramie County, Wyoming) that we believe will be drilled in the future.

Recent Developments

2018 Significant Acquisitions

In June 2018, we completed our largest acquisition to date in the Delaware Basin in Loving County, Texas and Lea County, New Mexico for approximately $41 million, subject to customary post-closing adjustments. We funded

66

the transaction with equity capital contributions and borrowings under our prior revolving credit facility. The purchase price was allocated $22.8 million to evaluated properties and $18.2 million to unevaluated properties.

In June 2018, we also entered into a definitive agreement to acquire additional acreage in the Delaware Basin for $24.3 million and closed on $22.0 million of the transaction in early August 2018 and anticipate that a second closing will occur in November 2018.

Term Loan Facility

On July 27, 2018, we entered into our term loan facility, which provides for an initial term loan of $125 million, a delayed draw term loan of $75 million and a revolving credit facility of $10 million for general corporate purposes. We used the proceeds of our term loan facility to repay the outstanding balance under our prior revolving credit facility and to fund mineral and royalty acquisitions. See “—Capital Requirements and Sources of Liquidity—Our Term Loan Facility.”

Business Environment

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 $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013. The Henry Hub spot market price for natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. As of June 30, 2018, the posted price for oil was $67.52 per barrel and the Henry Hub spot market price of natural gas was $2.88 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.

Wells Spud and Turned to Production

Drilling on our mineral and royalty interests is driven by the exploration and production companies that operate our DSUs. We monitor horizontal rig activity in an effort to identify wells that have been spud on our interests, as well as completion reports available on state websites to ascertain when a well has turned to production, to assist us with forecasting near-term production, revenue and free cash flow. Total wells spud on our acreage for the year ended December 31, 2017 increased by 76% compared to the year ended December 31, 2016. During the same period, total wells spud on our acreage as a percentage of total wells spud in our basins remained relatively unchanged, while our average realized prices for oil, natural gas and NGLs increased by 24.5%, 22.9% and 48.9%, respectively. The following table shows the number of wells spud in each of our basins during the years ended December 31, 2017 and 2016 according to information published by RSEG:

	Spud
	2016							2017
	Wells Spud On Our Acreage		Total Wells Spud in Basin		Our % Share of Total			Wells Spud On Our Acreage		Total Wells Spud in Basin		Our % Share of Total
Delaware		61		968		6	%		97		2,037		5	%
Midland		16		1,352		1	%		50		2,147		2	%
SCOOP		24		111		22	%		40		269		15	%
STACK		39		390		10	%		58		592		10	%
DJ		146		759		19	%		221		1,359		16	%
Williston		85		539		16	%		193		716		27	%
Other		5		8		63	%		3		11		27	%
Total		376		4,127		9	%		662		7,131		9	%

67

Total wells turned to production on our acreage for the year ended December 31, 2017 increased by 97% compared to the year ended December 31, 2016. During the same period, total wells turned to production on our acreage as a percentage of total wells completed in our basins remained relatively unchanged. The following table shows the number of wells turned to production in each of our basins during the years ended December 31, 2017 and 2016 according to information published by RSEG.

	Production
	2016							2017
	Wells Turned to Production On Our Acreage		Total Wells Turned to Production in Basin		Our % Share of Total			Wells Turned to Production On Our Acreage		Total Wells Turned to Production in Basin		Our Share of Total
Delaware		46		925		5	%		75		1,658		5	%
Midland		9		1,193		1	%		29		1,845		2	%
SCOOP		38		124		31	%		38		210		18	%
STACK		30		337		9	%		34		608		6	%
DJ		80		733		11	%		206		1,297		16	%
Williston		62		750		8	%		159		1,104		14	%
Other		12		13		92	%		6		31		19	%
Total		277		4,075		7	%		547		6,753		8	%

How We Evaluate Our Operations

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

• volumes of oil, natural gas and NGLs produced;

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

• commodity prices; and

• Adjusted EBITDA and Adjusted EBITDA ex lease bonus.

Volumes of Oil, Natural Gas and NGLs Produced

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

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

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

Commodity Prices

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, production levels, availability of transportation, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.

68

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

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

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

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

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

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

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

Hedging

We have in the past and may in the future enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Historically, we have only entered into minimal fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts may partially mitigate the effect of lower prices on our future revenue.

For the six months ended June 30, 2018 and the year ended December 31, 2017, our loss on commodity derivative instruments, net was $0.9 million and $0.1 million, respectively, and for the six months ended June 30, 2017 and the year ended December 31, 2016, we did not have any gain or loss on commodity derivative instruments. Our open oil and natural gas derivative contracts as of June 30, 2018 are detailed in “Note 6 –Derivative Instruments” to our consolidated financial statements included elsewhere in this prospectus.

In addition, the credit agreement governing our term loan facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves for up to 66 months in the future. As of

69

June 30, 2018, we had in place crude oil swaps through December 2019 covering 1% of our projected production from proved reserves, and as of December 31, 2017, we had in place crude oil swaps through September 2018 covering 1% of our projected production from proved reserves. We had no derivative contracts in place as of December 31, 2016.

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, interest expense, gain or loss on sale and distribution of equity securities, gain or loss on derivative instruments 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. For further discussion, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measures.”

Sources of Our Revenues

Our revenues are primarily derived from the mineral royalty payments we receive from our operators based on the sale of oil, natural gas and NGLs produced from our interests. Mineral 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.

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

	Six Months Ended June 30,						Year Ended December 31,
	2018			2017			2017			2016
Revenue
Mineral and royalty revenues
Oil sales		66	%		43	%		54	%		48	%
Natural gas sales		11	%		14	%		13	%		11	%
NGL sales		8	%		3	%		6	%		7	%
Total mineral and royalty revenue		85	%		60	%		73	%		66	%
Lease bonus revenue		15	%		40	%		27	%		34	%
Total revenue		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

70

horizontal well on line, lease operating expenses to produce our oil, natural gas and NGLs or 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 company that has 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 produced 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 and develop oil and natural gas properties. We use the full cost method of accounting, and, as such, all acquisition related costs 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 in the fourth quarter of each year based upon the year-end reserve report prepared by CG&A, unless circumstances indicate that there has been a significant change in reserves or costs.

General and Administrative

General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our staff, 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 anticipate incurring incremental G&A expenses relating to expenses associated with SEC reporting requirements, including annual and quarterly report to shareholders, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal expenses and investor relations expenses. These incremental G&A expenses are not reflected in the historical financial statements of our predecessor or the unaudited pro forma financial statements included elsewhere in this prospectus.

Interest Expense

We finance a portion of our working capital requirements and acquisitions with borrowings under our term loan facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our term loan facility in interest expense. In connection with the closing of this offering, we intend to partially repay our outstanding borrowings under our term loan facility.

71

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.

Results of Operations

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

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,
	2018		2017		Variance
	(Restated)
	(dollars in thousands, except for realized prices and per unit of production data)
Production
Oil (MBbls)		332		186		146		78.5	%
Natural gas (MMcf)		1,172		771		401		51.9	%
NGLs (MBbls)		104		33		71		212.6	%
Equivalents (MBoe)		631		348		283		81.5	%
Equivalents per day (Boe/d)		3,489		1,922		1,567		81.5	%
Revenues
Oil sales	$	20,455	$	8,707	$	11,748		134.9	%
Natural gas sales		3,309		2,726		583		21.4	%
NGL sales		2,622		599		2,023		337.4	%
Total mineral and royalty revenue		26,386		12,032		14,354		119.3	%
Lease bonus and other revenue	$	4,586	$	8,092	$	(3,506	)	(43.3	)%
Total revenue	$	30,972	$	20,124	$	10,848		53.9	%
Realized prices, without derivatives
Oil ($/Bbl)	$	61.61	$	46.81	$	14.80		31.6	%
Natural gas ($/Mcf)		2.82		3.53		(0.71	)	(20.1	)%
NGLs ($/Bbl)		25.17		17.99		7.18		39.9	%
Equivalents ($/Boe)	$	41.79	$	34.59	$	7.20		20.8	%
Realized prices, with derivatives(1)
Oil ($/Bbl)	$	60.52	$	46.81	$	13.71		29.3	%
Equivalents ($/Boe)		41.21		34.59		6.62		19.1	%
Other operating income
Gain on sale of oil and gas properties, net	$	—	$	94,558	$	(94,558	)	*	**
Operating expenses
Gathering, transportation and marketing	$	2,007	$	668	$	1,339		200.7	%
Severance and ad valorem taxes		1,642		597		1,045		175.2	%
Depreciation, depletion, and amortization		5,758		3,113		2,645		84.9	%
General and administrative		2,782		1,831		951		52.0	%
Total operating expenses	$	12,189	$	6,209	$	5,980		96.3	%
Other expenses
Interest expense, net	$	1,126	$	150	$	976		649.4	%
Loss on derivative instruments, net		914		—		914		*	**
Total other expenses	$	2,040	$	150	$	1,890		*	**

72

Note: Individual variance amounts may not calculate due to rounding.

(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.

*** Calculation is not meaningful.

Revenues

Total revenues for the six months ended June 30, 2018 increased by 54%, or $10.8 million, compared to the six months ended June 30, 2017. The increase was attributable to a $14.3 million increase in mineral and royalty revenue during the period, partially offset by a $3.5 million decrease in lease bonus revenue. The increase in mineral and royalty revenue was primarily the result of increased drilling and completion activity on our mineral and royalty interests, which resulted in a 82% increase in production volumes to 3,489 Boe/d and a corresponding increase in revenue of $9.8 million. Realized commodity prices increased 21% resulting in an additional $4.5 million increase in mineral and royalty revenue.

Oil revenue for the six months ended June 30, 2018 increased 135%, or $11.7 million, compared to the six months ended June 30, 2017. Oil production volumes increased 79% to 1,834 Boe/d resulting in a $6.8 million increase in oil revenue. The increase in oil production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in Colorado, Texas, North Dakota and Oklahoma. Realized oil prices increased 32% to $61.61 per barrel resulting in an additional increase in revenue of $4.9 million.

Natural gas revenue for the six months ended June 30, 2018 increased by 21.4%, or $0.6 million, compared the six months ended June 30, 2017. Natural gas production volumes grew 52% to 6,473 Mcf/d resulting in a $1.4 million increase in natural gas sales. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in Texas, Colorado and Oklahoma. Realized natural gas prices decreased 20% to $2.82 per Mcf resulting in an offsetting decrease in revenue of $0.8 million.

NGL sales for the six months ended June 30, 2018 increased 337%, or $2.0 million, compared to the six months ended June 30, 2017. NGL production volumes grew 213% to 576 barrels per day resulting in a $1.3 million increase in NGL sales, while realized NGL prices increased 40% to $25.17 per barrel resulting in an additional increase in revenue of $0.7 million.

The 43% decrease in lease bonus revenue for the six months ended June 30, 2018 was primarily attributable to decreased leasing activity on our interests in Oklahoma, partially offset by an increase in leasing activity in Texas. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Other operating income

Gain on sale of oil and gas properties, net. On February 28, 2017, Brigham Operating and Brigham Resources Midstream, LLC, wholly owned subsidiaries of Brigham Resources, closed on the sale of substantially all of their Southern Delaware Basin leasehold and related assets, including certain mineral and royalty interests owned by Brigham Resources, to a third-party public entity. The proceeds for mineral and royalty interests represented $156.7 million of the net adjusted sales price and consisted of cash of $111.1 million and shares valued at $45.6 million. The mineral and royalty interests sold represented approximately 12% in aggregate of Brigham Resources’ total proved reserves as of December 31, 2016. As a result of the sale, the relationship between capitalized costs and proved reserves was altered significantly and Brigham Resources recorded a gain of $94.6 million.

73

Operating and other expenses

Gathering, transportation and marketing expenses. For the six months ended June 30, 2018, gathering, transportation and marketing expenses increased 201%, or $1.3 million, compared to the six months ended June 30, 2017, which was largely driven by the increase in our production volumes.

Severance and ad valorem taxes. For the six months ended June 30, 2018, severance and ad valorem taxes increased by 175%, or $1.0 million, over the six months ended June 30, 2017, primarily due to higher severance taxes associated with oil revenue as a result of higher oil production volumes and higher oil prices.

Depreciation, depletion and amortization. DD&A expense increased by 85%, or $2.6 million, for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. Higher production volumes increased our DD&A expense by $2.2 million, and a higher depletion rate increased our DD&A expense by $0.4 million.

General and administrative. For the six months ended June 30, 2018, G&A expense increased by 52%, or $1.0 million, compared to the six months ended June 30, 2017 as a result of increased headcount and incremental business development expenses.

Interest expense. Interest expense increased by $1.0 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 due to greater average outstanding borrowings and higher interest rates under our prior revolving credit facility. The need for greater borrowings was driven by our increased acquisition pace in 2018 relative to 2017.

Loss on derivative instruments, net. For the six months ended June 30, 2018, we recognized a net loss on derivative instruments of $0.9 million, which is attributable to oil derivative instruments. We realized $0.4 million of losses on our settled derivative instruments during the six months ended June 30, 2018. We did not have any outstanding hedges for the six months ended June 30, 2017 and thus did not recognize any gain or loss related to derivative instruments.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

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:

	Year Ended December 31,
	2017		2016		Variance
	(dollars in thousands, except for realized prices and per unit of production data)
Production
Oil (MBbls)		454		262		192	73.3	%
Natural gas (MMcf)		1,768		955		813	85.1	%
NGLs (MBbls)		109		90		19	21.1	%
Equivalents (MBoe)		858		512		346	67.6	%
Equivalents per day (Boe/d)		2,352		1,399		953	68.1	%
Revenue
Oil sales	$	22,092	$	10,244	$	11,848	115.7	%
Natural gas sales		5,492		2,422		3,070	126.8	%
NGL sales		2,482		1,380		1,102	79.9	%
Total mineral and royalty revenue		30,066		14,046		16,020	114.1	%
Lease bonus and other revenue	$	10,842	$	7,187	$	3,655	50.9	%
Total revenue	$	40,908	$	21,233	$	19,675	92.7	%

74

	Year Ended December 31,
	2017		2016		Variance
	(dollars in thousands, except for realized prices and per unit of production data)
Realized prices, without derivatives
Oil ($/Bbl)	$	48.61	$	39.04	$	9.57	24.5	%
Natural gas ($/Mcf)		3.11		2.53		0.58	22.9	%
NGLs ($/Bbl)		22.71		15.25		7.46	48.9	%
Equivalents ($/Boe)	$	35.02	$	27.43	$	7.59	27.7	%
Realized Prices, with derivatives(1)
Oil ($/Bbl)	$	48.61	$	39.04	$	9.57	24.5	%
Equivalents ($/Boe)		35.02		27.43		7.59	27.7	%
Other operating income
Gain on sale of oil and gas properties, net	$	94,551	$	—	$	94,551	*	**
Operating expenses
Gathering, transportation and marketing	$	1,754	$	820	$	934	113.9	%
Severance and ad valorem taxes		1,601		629		972	154.5	%
Depreciation, depletion, and amortization		6,955		4,913		2,042	41.6	%
General and administrative		3,935		3,751		184	4.9	%
Total operating expenses	$	14,245	$	10,113	$	4,132	40.9	%
Other expenses
Interest expense, net		556		298		258	86.6	%
Loss on derivative instruments, net		121		—		121	*	**
Total other expenses	$	677	$	298	$	379	127.2	%

(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.

*** Calculation is not meaningful.

Revenues

Total revenue for the year ended December 31, 2017 increased by 93%, or $19.7 million, compared to the year ended December 31, 2016. The increase was attributable to a $16.0 million increase in royalty revenue during the period and a $3.7 million increase in lease bonus revenue. The increase in royalty revenue was primarily the result of increased drilling and completion activity on our mineral and royalty interests, which resulted in a 68% increase in production volumes to 2,352 Boe/d and a $10.2 million increase in royalty revenue, along with a 28% increase in realized commodity prices, resulting in an additional $5.8 million increase in royalty revenue.

Oil sales for the year ended December 31, 2017 increased 116%, or $11.8 million, compared to the year ended December 31, 2016. Oil sales volumes increased 73% to 1,244 Boe/d resulting in a $7.9 million increase in oil sales, while realized oil prices increased 25% to $48.61 per barrel resulting in an additional $3.9 million increase in oil sales. The increase in production volumes for the year ended December 31, 2017 was primarily attributable to increased drilling on our existing properties in Colorado, Texas, North Dakota and Oklahoma.

Natural gas sales for the year ended December 31, 2017 increased by 127%, or $3.1 million, compared to the year ended December 31, 2016. Natural gas sales volumes grew 85% to 4,844 Mcf/d resulting in a $2.1 million increase in natural gas sales, while realized natural gas prices increased 23% to $3.11 per Mcf resulting in an additional $1.0 million increase in natural gas sales. The increase in production volumes for the year ended December 31, 2017 was primarily attributable to increased drilling on our interests in Colorado and Oklahoma.

75

NGL sales for the year ended December 31, 2017 increased 80%, or $1.1 million, compared to the year ended December 31, 2016. NGL sales volumes grew 21% to 299 barrels per day resulting in a $0.2 million increase in NGL sales, while realized NGL prices increased 49% to $22.71 per barrel resulting in an additional $0.9 million increase in NGL sales.

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The increase of 51% in revenue from lease bonus payments for the year ended December 31, 2017 was primarily attributable to increased leasing activity on our interests in Oklahoma. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Other operating income

Gain on sale of oil and gas properties, net. On February 28, 2017, Brigham Operating and Brigham Resources Midstream, LLC, wholly owned subsidiaries of Brigham Resources, closed on the sale of substantially all of their Southern Delaware Basin leasehold and related assets, including certain mineral and royalty interests owned by Brigham Resources, to a third-party public entity. The proceeds for mineral and royalty interests represented $156.7 million of the net adjusted sales price and consisted of cash of $111.1 million and shares valued at $45.6 million. The mineral and royalty interests sold represented approximately 12% in aggregate of Brigham Resources’ total proved reserves as of December 31, 2016. As a result of the sale, the relationship between capitalized costs and proved reserves was altered significantly and Brigham Resources recorded a gain of $94.6 million.

Operating and other expenses

Gathering, transportation and marketing expenses. For the year ended December 31, 2017, gathering, transportation and marketing expenses increased 114%, or $0.9 million, compared to the year ended December 31, 2016, which was largely driven by the 68% increase in our production volumes.

Severance and ad valorem taxes. For the year ended December 31, 2017, severance and ad valorem taxes increased by 155%, or $1.0 million, over the year ended December 31, 2016, generally as a result of higher production volumes and higher commodity prices.

Depreciation, depletion and amortization. DD&A expense increased by 42%, or $2.0 million, for the year ended December 31, 2017 as compared to the year ended December 31, 2016. Higher production volumes increased our DD&A expense by $2.9 million, offset by $0.9 million as a result of our lower depletion rate.

General and administrative. For the year ended December 31, 2017, G&A expense increased by $0.2 million, or 5%, compared to 2016 as a result of increased headcount and incremental business development expenses.

Interest expense. Interest expense increased by $0.2 million for the year ended December 31, 2017 compared to 2016 due to higher average outstanding borrowings and higher interest rates under our credit facility, which were predominantly driven by our acquisition of a larger number of oil, natural gas and NGL properties in 2017 as compared to the year ended December 31, 2016.

Loss on derivative instruments, net. For the year ended December 31, 2017, we recognized a net loss on derivative instruments of $0.1 million, which is attributable to derivative instruments based on the price of oil. None of the losses we recognized in 2017 were realized losses. We did not recognize any gain or loss related to derivative instruments for the year ended December 31, 2016.

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.

76

Corporate Reorganization

The historical consolidated financial statements included in this prospectus are based on the financial statements of our accounting predecessor, Brigham Resources, excluding the historical results and operations of Brigham Operating, prior to our corporate reorganization. As a result, the historical consolidated 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 Resources will be a wholly owned subsidiary of Brigham LLC. After giving effect to the corporate reorganization and this offering, Brigham Minerals will own an approximate                 % interest in Brigham LLC (or                 % if the underwriters exercise their option to purchase additional shares in full). In addition, Brigham Minerals will be the sole managing member of Brigham LLC and will be responsible for all operational, management and administrative decisions relating to Brigham LLC’s business.

Public Company Expenses

Upon completion of this offering, we expect to 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 with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations 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 historical results of operations.

Income Taxes

Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor, Brigham Resources, 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 will be passed through to the members of Brigham LLC, including Brigham Minerals, following our corporate reorganization. Accordingly, the financial data attributable to Brigham Resources 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). We estimate that Brigham Minerals would have been subject to U.S. federal, state and local taxes at a blended statutory rate of 36.5% of 2017 pre-tax earnings and will be subject to a blended statutory rate of 23.8%. Based on blended statutory rates of 36.5% and 23.8% for 2017 and 2018, respectively, Brigham Minerals would have incurred pro forma income tax expense for the year ended December 31, 2017 and the six months ended June 30, 2018 of approximately $42.6 million and $4.2 million, respectively.

Capital Requirements and Sources of Liquidity

Historically, our primary sources of liquidity have been capital contributions from the Existing Owners, borrowings under our debt arrangements and cash flows from operations. Following the completion of this offering, we expect our primary sources of liquidity to be the net proceeds retained from this offering, cash flows from operations, borrowings under our term loan facility and proceeds from any future issuances of debt or equity securities. We expect our primary use of capital will be for the payment of dividends to our stockholders and for investing in our business, specifically the acquisition of additional mineral and royalty interests.

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, our only capital expenditures are related to our acquisition of additional mineral and royalty

77

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, 2018 and the twelve months ending December 31, 2017, we incurred approximately $105.0 million and $102.1 million, respectively, for acquisition-related capital expenditures. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements and other factors to determine the effects on our liquidity. Based upon our current oil, natural gas and NGL price expectations for the remainder of 2018, following the closing of this offering, we believe that our cash flow from operations, additional borrowings under our term loan facility and a portion of the proceeds from this offering will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, asset sales, offerings of debt and equity 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 July 31, 2018, we had $150 million outstanding under our term loan facility with $50 million remaining under the delayed draw down component and $10 million available under the related revolving credit facility. We intend to use a portion of the net proceeds from this offering to partially repay the outstanding borrowings under our term loan facility.

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $22.0 million and $20.1 million at June 30, 2018 and December 31, 2017, respectively, as compared to $40.5 million at December 31, 2016. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. However, 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. Our cash and cash equivalents balance totaled $1.6 million, $6.9 million and $34.0 million at June 30, 2018, December 31, 2017 and December 31, 2016, respectively. We expect that our cash flows from operations and availability under our term loan facility after application of the estimated net proceeds from this offering, as described under “Use of Proceeds,” will be sufficient to fund our working capital needs. We expect that the pace of our operators’ drilling 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,						Year Ended December 31,
	2018			2017			2017			2016
	(Restated)
	(In thousands)
Net cash provided by operating activities	$	14,899		$	15,290		$	29,401		$	14,483
Net cash provided by/(used in) investing activities		(109,203	)		80,156			26,172			(91,826	)
Net cash (used in)/provided by financing activities		89,008			(123,669	)		(82,647	)		93,140

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2018 and 2017

Operating activities. Net cash provided by operating activities is primarily affected by the prices of oil, natural gas and NGLs, production volumes, lease bonus revenue and changes in working capital. The 82%

78

increase in production volumes and the 21% increase in realized prices during the six months ended June 30, 2018 discussed above were offset by increases in operating expenses and accounts receivable. Typically, an operator makes initial payment related to a new well approximately six months after the well has come on line, often comprised of multiple months of production.

Investing activities. Net cash used in investing activities is primarily comprised of acquisitions of oil and natural gas mineral and royalty interests, net of dispositions. For the six months ended June 30, 2018, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $105.0 million, as well as restricted cash held in escrow for pending transactions totaling $4.0 million. Our purchase and sale agreements and escrow agreements typically provide for a 30 day period for us to verify title. For the six months ended June 30, 2017, our net cash provided by investing activities was primarily a result of divestiture proceeds of $111.0 million from the February 2017 sale of mineral and royalty interests, partially offset by acquisitions of mineral and royalty interests of $30.5 million.

Financing activities. Net cash provided by financing activities for the six months ended June 30, 2018 included $46.0 million in net capital contributions from the Existing Owners and $43.0 million in additional borrowings under our prior revolving credit facility. Net cash used in financing activities for the six months ended June 30, 2017 included $113.7 million in net capital distributions to the Existing Owners, partially offset by $10.0 million in net borrowings under our prior revolving credit facility.

Analysis of Cash Flow Changes Between the Year Ended December 31, 2017 and 2016

Operating Activities. The increase in net cash provided by operating activities for the year ended December 31, 2017 as compared to the prior year is primarily due to a 68% increase in production volumes and a 28% increase in realized prices, partially offset by a 43% increase in operating expenses.

Investing Activities. In 2017, our net cash provided by investing activities was primarily a result of divestiture proceeds of $111.1 million from the February 2017 sale of mineral and royalty interests and proceeds of $17.9 million from a sale of equity securities, which was partially offset by the acquisition of mineral and royalty interests totaling $101.4 million. In 2016, our net cash used in investing activities was primarily related to acquisitions of mineral and royalty interests.

Financing Activities. Net cash used in financing activities in 2017 included $94.5 million in net capital distributions to the Existing Owners, partially offset by $11.9 million in net borrowings under our prior revolving credit facility, net of $0.1 million in associated closing costs. Net cash provided by financing activities in 2016 included $78.4 million in net capital contributions from the Existing Owners and $14.8 million in net borrowings under our revolving credit facility, net of $0.2 million in associated closing costs.

Our Term Loan Facility

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

Our term loan facility matures on July 27, 2024 and provides for a $125 million initial term loan and a delayed draw term loan (“DDTL”) of $75 million, which will be subject to certain customary conditions. In addition, a $10 million revolving credit facility is available for general corporate purposes. Our term loan facility bears 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%. Upon the consummation of this offering, each of the foregoing margins will decrease by 0.50% if at the end of the most recently completed fiscal quarter our total net leverage ratio (as defined in the credit agreement governing our term loan facility) is less than or equal to 2.00 to 1.00.

79

Upon the consummation of this offering, our term loan facility will amortize at a rate equal to 1.00% per annum, though the credit agreement governing our term loan facility will require us to use at least 25% of our excess cash flow (as defined in the credit agreement) for any fiscal year beginning with the fiscal year ending December 31, 2019 to prepay the outstanding balance under our term loan facility if our total net leverage ratio (as defined in the credit agreement) is greater than 2.00 to 1.00. In addition, the entire outstanding balance of interest and principal must be repaid on the maturity date of July 27, 2024.

Under the credit agreement that governs our term loan facility, we must maintain an asset coverage ratio, which is the ratio of (a) the sum of (i) the present value of our and the other loan parties’ proved reserves (as set forth in the most recently delivered reserve report) that are subject to a mortgage in favor of the administrative agent under our term loan facility plus (ii) the Swap Mark-to-Market Value (as defined in the credit agreement) as of such date to (b) Consolidated Senior Secured First Lien Indebtedness (as defined in the credit agreement) as of such date of not less than 1.75 to 1.00.

As of July 31, 2018, we had $150 million of outstanding borrowings under our term loan facility. The credit agreement governing our term loan facility also requires us to maintain compliance with a total net leverage ratio, which is the ratio, on a pro forma basis, of (a) Consolidated Total Indebtedness (as defined in the credit agreement) as of such date less up to $25 million of cash and certain permitted investments to (b) two times our Consolidated EBITDA (as defined in the credit agreement) for the most recently completed Test Period (as defined in the credit agreement) of not more than 4.00 to 1.00 as of the last day of any fiscal quarter.

Prior Revolving Credit Facility

Prior to entering into our term loan facility, we maintained a revolving credit facility (our “prior revolving credit facility”) with Wells Fargo Bank, N.A., as administrative agent, and certain lenders party thereto with commitments of $150 million (subject to a borrowing base). We paid the $70 million outstanding balance under our prior revolving credit facility with proceeds from our term loan facility.

Contractual Obligations

A summary of our contractual obligations as of June 30, 2018 is provided in the following table:

	Payments Due by Period for the Year Ending December 31,
	2018		2019		2020		2021		2022		Thereafter		Total
	(In thousands)
Long-term debt obligations(1)	$	—	$	—	$	—	$	70,000	$	—	$	—	$	70,000
Office lease		179		436		449		461		472		160		2,157
Total(2)	$	179	$	436	$	449	$	70,461	$	472	$	160	$	72,157

(1) As of July 31, 2018, we had $150 million outstanding under our term loan facility and $50 million of additional borrowing capacity available under the delayed draw term loan and $10 million of additional borrowing capacity available under the related revolving credit facility. We intend to use a portion of the net proceeds from this offering to partially repay borrowings under our term loan facility. Please see “Use of Proceeds.”

(2) Subsequent to December 31, 2017, we entered into a new lease for an extended office space. See “Note 10—Subsequent Events” to our consolidated financial statements included elsewhere in this prospectus.

Quantitative and Qualitative Disclosure 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

80

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 and natural gas 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 low of $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013, and as of June 30, 2018, the posted price for oil was $67.52 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 $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014, and as of June 30, 2018, the Henry Hub spot market price of natural gas was $2.88 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 “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 is sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. A substantial or extended decline in commodity prices 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 $0.5 million change in our oil revenues for the year ended December 31, 2017. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the year ended December 31, 2017. A $1.00 per barrel change in NGL prices would have resulted in a $0.1 million change in our NGL revenues for the year ended December 31, 2017. Royalties on oil sales contributed 54% of our total revenues for the year ended December 31, 2017. Royalties on natural gas sales contributed 13% and royalties on NGL sales contributed 6% of our total revenues for the year ended December 31, 2017.

We have in the past and may in the future 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. The credit agreement governing our term loan facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves for up to 66 months in the future. As of June 30, 2018, we had in place crude oil swaps through December 2019 covering 1% of our projected production from proved reserves, and as of December 31, 2017, we had in place crude oil swaps through September 2018 covering 1% of our projected production from proved reserves. We had no derivative contracts in place as of December 31, 2016.

81

Our open positions as of June 30, 2018 are as follows:

Description & Production Period	Volume		Weighted Average Swap Price
	(Bbl)		($/Bbl)
Crude Oil Swaps:
July 2018 — September 2018(1)		55,000	$	61.32
October 2018 — December 2018		15,000	$	67.59
January 2019 — March 2019		15,000	$	63.61
April 2019 — June 2019		15,000	$	63.61
July 2019 — September 2019		15,000	$	63.61
October 2019 — December 2019		15,000	$	63.61
Total		130,000	$	63.10

(1) Includes swaps for 10,000 Bbl valued as a liability of $0.1 million that matured on June 30, 2018 and will be settled in July 2018.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

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. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

At July 31, 2018, we had $150 million of debt outstanding under our term loan facility, with an assumed weighted average interest rate of 7.58%. Interest is calculated under the terms of the credit agreement governing our term loan facility 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%. Upon the consummation of this offering, each of the foregoing margins will decrease by 0.50% if at the end of the most recently completed fiscal quarter our total net leverage ratio (as defined in the credit agreement governing our term loan facility) is less than or equal to 2.00 to 1.00. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $1.5 million per year, with a corresponding decrease in our results of operations. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our predecessor’s consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our predecessor’s financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

82

A complete list of our predecessor’s significant accounting policies are described in the notes to our predecessor’s audited financial statements for the year ended December 31, 2017 included elsewhere in this prospectus.

Use of Estimates

The preparation of consolidated financial statements in conformity 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 consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.

Our predecessor’s consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of DD&A and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by CG&A, an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments and revenue accruals.

Receivables

Receivables consist of mineral and royalty income due from operators for oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Receivables from third parties for which we did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates are based upon historical actual data if available, otherwise on engineering estimates. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.

We routinely review outstanding balances, assess the financial strength of our customers and record a reserve for amounts not expected to be fully recovered. We did not record any allowance for doubtful accounts for the years ended December 31, 2017 and 2016.

Derivative Instruments

In the normal course of business, we are exposed to certain risks, including changes in the prices of oil, natural gas and NGLs and interest rates. We have historically entered into derivative contracts to manage our exposure to these risks. Our risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. We do not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. We do not specifically designate derivative instruments as cash flow hedges, even though they reduce our exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in our predecessor’s consolidated statements of operations within loss on derivative instruments, net.

83

Oil and Gas Properties

We use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.

Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by net equivalent proved reserves at the beginning of the period.

Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition and leasehold costs and capitalized interest. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties in 2017 or 2016.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

Natural gas volumes are converted to Boe at the rate of six thousand Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

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 lower of cost or fair value of unevaluated properties (the ceiling limitation). A ceiling limitation is calculated at each reporting period. If total capitalized costs, net of accumulated DD&A, are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. 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. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using the 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). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas.

As of December 31, 2017 and 2016, the full cost ceiling value of our reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12 months ended December 31, 2017 and 2016 of $51.34 and $42.60, respectively, per barrel for oil, adjusted by area for energy content, transportation fees and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12 months ended December 31, 2017 and 2016 of $2.99 and $2.47, respectively, per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. Using these prices, the net book value of oil and natural gas was above the ceiling limitation and no write-off was necessary.

84

Revenue Recognition

Royalty interests represent the right to receive revenues (oil and natural gas sales), less production and ad valorem taxes and post-production costs. Revenue is recorded when title passes to the purchaser. Royalty interests have no rights or obligations to explore, develop or operate the property once it is leased to a third-party operator and do not incur any of the costs of exploration, development and operation of the property.

We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

Pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. We have no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

We earn lease bonus revenues and lease extension revenues (collectively referred to as “lease bonus revenue”) from leasing mineral interests to exploration and production companies in exchange for a royalty interest. Lease bonus revenues are recognized when received, at which time we give up the right to develop the land ourselves or to lease it to another party.

Recently Issued Accounting Pronouncements

See “Note 2—Significant Accounting Policies—Recently Issued Accounting Standards” to our consolidated financial statements as of December 31, 2017 included elsewhere in this prospectus, for a discussion of recent accounting pronouncements.

Under the JOBS Act, we expect that we will meet the definition of an “emerging growth company,” which would allow us to take advantage of an extended transition period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of Sarbanes-Oxley, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of Sarbanes-Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC for the year ended December 31, 2018. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 until 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. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

85

Material Weaknesses and Remediation

Prior to the completion of this offering, Brigham Resources has been a private company that has required fewer accounting personnel to execute its accounting processes and supervisory resources to address its internal control over financial reporting, which we believed were adequate for a private company of its size and industry. In preparation for ongoing operations of a public company, we engaged third-party consultants to assist with the documentation, implementation and testing of enhanced accounting processes and control procedures required to meet the financial reporting requirements of a public company. Nevertheless, the design and execution of our controls has not been sufficiently tested by individuals with financial reporting oversight roles or by our third party consultants. In connection with the preparation and review of our unaudited condensed consolidated financial statements for the nine months ended September 30, 2018, our management identified certain material weaknesses related to our risk assessment processes and certain controls related to revenues and certain recent transactions. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. After identifying such material weaknesses, which resulted in errors in our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018, we reviewed our audited financial statements for the years ended December 31, 2017 and 2016 for additional potential accrual and presentation errors, which resulted in an immaterial correction of the presentation of gains and losses on sales of assets to include such gains and losses in other operating income for all periods presented. For more information regarding the impact of these material weaknesses on our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018, please see “Risk Factors—Risks Related to this Offering and Our Class A Common Stock—We have identified and are in the process of remediating certain material weaknesses related to our risk assessment processes and certain controls related to revenues and certain recent transactions. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may cause current and potential stockholders to lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.” and Note 1 to our unaudited interim consolidated financial statements included elsewhere in this prospectus.

We are working to remediate the material weaknesses, which originated in our internal control over financial reporting described above. To date, we have taken steps to enhance our internal control environment, including implementing additional review procedures that we believe have remediated certain aspects of the identified material weaknesses. We have also engaged a third-party consultant to develop a plan for remediating the remaining aspects of the identified material weaknesses, including implementing additional review procedures, employing additional finance and accounting personnel and reevaluating our internal reporting procedures with respect to revenue recognition. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses. In addition, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2017 and 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and our operators tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in the areas in which our properties are located.

Off-Balance Sheet Arrangements

Currently, neither we nor our predecessor have off-balance sheet arrangements.

86

BUSINESS

Our Company

Overview

We formed our company in 2012 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 basins across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our shareholders by both capturing growth in free cash flow from the continued development of our existing portfolio of 10,187 undeveloped horizontal drilling locations unburdened by development capital expenditures or lease operating expenses, as well as leveraging our highly experienced technical evaluation team to continue to execute upon our scalable business model of sourcing, methodically evaluating and integrating accretive minerals acquisitions in the core of top-tier, liquids-rich resource plays.

Our portfolio is comprised of mineral and royalty interests across four of the most highly economic, liquids-rich resource basins in the continental United States, including the Permian Basin in Texas and New Mexico, the SCOOP and STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota. Our highly technical approach towards mineral acquisitions in the geologic core of top-tier resource plays has purposefully led to a concentrated portfolio covering 37 of the most highly active counties for horizontal drilling in the continental United States. According to RSEG, an affiliate of Warburg Pincus, as of June 30, 2018, operators have deployed 59% of the horizontal rig fleet, and 66% of the liquids-focused horizontal rig fleet, in the continental United States in these same 37 counties, which we believe will continue to result in the consistent long-term development of our asset base. On a pro forma basis giving effect to our portfolio of 61,219 net royalty acres at June 30, 2018 as if we had owned it since January 1, 2013, we estimate that the production volumes net to our interests would have grown at an approximate 53% compound annual growth rate from the beginning of 2013 through June 30, 2018, despite crude oil prices decreasing substantially during that same time period, as illustrated by the following chart.

Since inception, we have executed on our technically driven, disciplined acquisition approach and have closed 1,229 transactions with third-party mineral and royalty interest owners as of June 30, 2018. Over the past four and a half years, we have increased our mineral and royalty interests from 10,209 net royalty acres as of December 31, 2013, to 61,219 net royalty acres as of June 30, 2018, which represents a 49% compound annual

87

growth rate in our mineral and royalty interests over that period. See “—Our Company—Our Mineral and Royalty Interests” for a discussion of how we calculate net royalty acres.

The following table summarizes certain information regarding our net royalty acreage acquisitions during each year of our operations and for the six months ended June 30, 2018.

	2012		2013		2014		2015		2016		2017		2018(1)		Total
Net Royalty Acres (NRAs) Acquired		473		9,736		17,317		7,192		9,791		9,361		7,349		61,219
Number of Acquisitions		15		313		380		152		121		153		95		1,229
Average NRAs per Acquisition		32		31		46		47		81		61		77		50
NRAs at Period End		473		10,209		27,526		34,718		44,509		53,870		61,219		61,219

(1) As of June 30, 2018.

By targeting core, top-tier acreage, our interests have continued to see rapid development with a total of approximately 662 horizontal wells spud on our mineral and royalty interests during 2017. This significant activity has similarly translated into rapid production growth with our production volumes growing approximately 68% from 2016 to 2017. Further, our production volumes are comprised of high-value liquids with 69% of our volumes for the six months ended June 30, 2018 composed of crude oil and NGLs, which represents 87% of our mineral and royalty revenue for the period. The combined growth in our production volumes and the high percentage of liquids production have resulted in a 114% increase in our royalty revenue from 2016 to 2017. We expect to see future organic growth in our production, revenue and free cash flow from 586 DUCs across our interests and approximately 751 horizontal drilling permits as of June 30, 2018 (excluding Laramie County, Wyoming), all of which are expected to occur without additional capital expenditure outlays. Development of permits on our acreage is driven by robust and consistent rig activity on meaningful portions of our acreage. Over the twelve months ended June 30, 2018, there have been an average of 27 horizontal rigs developing 865 net mineral acres across our basins, which we believe provides visibility toward future production growth.

Average Monthly Rigs on Acreage	Average Monthly NMA Under Development

In addition to existing near-term development, our permitted horizontal drilling locations represent only approximately 7% of the remaining proved, probable and possible undeveloped horizontal drilling locations incorporated by CG&A in our reserve report as of June 30, 2018, thereby providing us with a substantial long-term drilling inventory on our acreage.

Our management team has a long history of identifying, acquiring, delineating, developing and successfully monetizing positions in liquids-rich resource basins. Prior to forming Brigham Resources, a subset of our management team formed Brigham Exploration, where it oversaw the identification, acquisition, delineation and development of approximately 375,000 net acres in the Williston Basin prior to Brigham Exploration’s sale to Statoil in December 2011 for $4.4 billion. Our team utilized its technical capabilities in the Williston Basin to identify and acquire highly prospective leasehold acreage with favorable geologic attributes and employed advanced drilling and completion technologies to cost-effectively extract oil and natural gas. Immediately

88

following the sale of Brigham Exploration, a subset of our management team then formed Brigham Operating and executed on these same strategies in the Southern Delaware Basin in West Texas. By applying rigorous geologic evaluation criteria, Brigham Operating was an early entrant in the Southern Delaware Basin in Pecos County, Texas, where it assembled an approximate 80,185 net acre leasehold position in a largely contiguous block. Brigham Operating sold these assets to Diamondback Energy, Inc., in February 2017 for approximately $2.55 billion.

Our Mineral and Royalty Interests

Mineral interests are real-property interests that are typically perpetual and grant both ownership of the oil, natural gas and NGLs under a tract of land and the right to lease development rights to a third party. When those rights are leased, usually for a three-year primary term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a percentage of production or revenue.

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. Mineral and royalty owners only incur their proportionate share of severance and ad valorem taxes, as well as in some instances, gathering, transportation and marketing costs. As a result, operating margins and therefore free cash flow for a mineral and royalty interest owner are higher as a percentage of revenue than for a traditional exploration and production operating company.

As of June 30, 2018, our mineral and royalty interests consisted of 42,572 net mineral acres, which have been leased to operators to explore for and develop our oil and natural gas rights at a weighted average royalty of 18.0%. Typically, within the minerals industry, mineral owners standardize ownership to a 12.5%, or 1/8^th, royalty interest, which is referred to as a “net royalty acre.” Our net mineral acres standardized to a 1/8^th royalty equate to 61,219 net royalty acres. When standardized on a 100% royalty basis, these 61,219 net royalty acres equate to 7,652 “100% royalty acres.” Our 61,219 net royalty acres are located within 1,216 DSUs, which are the areas designated in a spacing order or unit designation as a unit and within which operators drill wellbores to develop our oil and natural gas rights. Our DSUs, in aggregate, consist of a total of 1,260,350 gross acres, which we refer to as our “gross DSU acreage.” Within our gross DSU acreage, we expect to have an interest in wells currently producing or that will be drilled in the future. The following table summarizes our mineral and royalty interest position and the conversion of our interests between net mineral acres, net royalty acres and 100% royalty acres as of June 30, 2018.

Net Mineral Acres	Weighted Average Royalty	Net Royalty Acres(1)	100% Royalty Acres(2)	Gross DSU Acres	Implied Average Net Revenue Interest per Well(3)
42,572	18.0%	61,219	7,652	1,260,350	0.61%

(1) Standardized to a 1/8^th royalty (i.e., 42,572 net mineral acres * 18.0% / 12.5%).

(2) Standardized to a 100% royalty (i.e., 61,219 net royalty acres * 12.5%).

(3) Calculated as number of 100% royalty acres per gross DSU acre (i.e., 7,652 100% royalty acres / 1,260,350 gross DSU acres).

In addition to mineral interests, which represented approximately 97% of our net royalty acres as of June 30, 2018, we also own other types of non-cost-bearing interests, including:

• Nonparticipating Royalty Interests. NPRIs are royalty interests that are carved out of mineral interests. NPRIs are typically perpetual and, similar to mineral interests, have the right to a percentage of production revenues extracted from the mineral and royalty acreage. NPRIs do not have the associated executive right to lease or to receive lease bonuses. We combine our mineral and NPRI assets into one category because they share many of the same characteristics due to the nature of the underlying interest. As of June 30, 2018, we owned approximately 1,247 net royalty acres of NPRIs.

89

• Overriding Royalty Interests. ORRIs are royalty interests that burden the working interest ownership (e.g. lessee’s ownership) of a lease and represent the right to receive a fixed percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated lease expires and are therefore not perpetual in nature. As of June 30, 2018, we owned approximately 276 net royalty acres of ORRIs.

Our Properties

Focus Areas

Our mineral and royalty interests are primarily located in six resource plays, which we refer to as our focus areas. These include the Delaware and Midland Basins in the Permian Basin, the SCOOP and STACK plays in the Anadarko Basin, the DJ Basin and the Williston Basin. The following chart shows our overall exposure to each of our primary focus areas based on our net royalty acres in each focus area as of June 30, 2018.

In addition, the following table summarizes certain information regarding our primary focus areas. Our average daily net production for the three months ended June 30, 2018 was comprised 53% of oil production, 31% of natural gas production and 16% of NGL production.

Basin	Acreage as of June 30, 2018														Gross Horizontal Producing Well Count as of June 30, 2018(4)		Average Daily Net Production for Three Months Ended June 30, 2018(5) (Boe/d)
	Net Mineral Acres		Weighted Average Royalty			Net Royalty Acres(1)		100% Royalty Acres(2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well(3)
Delaware		9,794		21.3	%		16,691		2,086		179,383		1.16	%		258		908
Midland		2,127		15.6	%		2,659		332		49,938		0.67	%		52		116
SCOOP		5,251		18.5	%		7,777		972		161,247		0.60	%		240		215
STACK		5,889		17.8	%		8,373		1,047		159,970		0.65	%		156		416
DJ		11,945		15.9	%		15,224		1,903		160,897		1.18	%		733		1,452
Williston		5,160		16.3	%		6,747		843		471,685		0.18	%		1,238		544
Other		2,406		19.5	%		3,748		469		77,230		0.61	%		62		72
Total		42,572		18.0	%		61,219		7,652		1,260,350		0.61	%		2,739		3,723

90

Note: Individual amounts may not add up to totals due to rounding.

(1) Standardized to a 1/8^th royalty.

(2) Standardized to a 100% royalty.

(3) Calculated as number of 100% royalty acres per gross DSU acre.

(4) Represents number of horizontal producing wells across all DSUs in which we participate.

(5) Represents actual production plus allocated accrued volumes attributable to the period presented.

Permian Basin—Delaware and Midland Basins

The Permian Basin ranges from West Texas into southeastern New Mexico and is currently the most active area for horizontal drilling in the United States. The Permian Basin is further subdivided into the Delaware Basin in the west and the Midland Basin in the east. As of June 30, 2018, according to RSEG, there were approximately 226 and 150 horizontal rigs running in the Delaware and Midland Basins, respectively. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Delaware Basin are prospective for seven or more producing zones of economic horizontal development including the Wolfcamp A, B, C and XY; First, Second and Third Bone Spring; and the Avalon. Our Delaware Basin mineral and royalty interests are located in Reeves, Loving, Ward, Pecos, Culberson and Winkler Counties, Texas with our remaining interests located in Lea County, New Mexico. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Midland Basin are prospective for five or more producing zones of economic horizontal development including the Middle Spraberry; Lower Spraberry; and Wolfcamp A, B and C. Our Midland Basin mineral and royalty interests are located in Martin, Midland, Upton, Howard and Reagan Counties, Texas.

Anadarko Basin—SCOOP and STACK Plays

The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens and McClain Counties. As of June 30, 2018, according to RSEG, there were approximately 71 horizontal rigs running in the SCOOP play. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the SCOOP play are prospective for two or more producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo and Blaine Counties. As of June 30, 2018, according to RSEG, there were approximately 27 horizontal rigs running in the STACK play. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the STACK play are prospective for four or more producing zones of economic horizontal development including multiple benches within both the Meramec and Woodford formations.

DJ Basin

The DJ Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. As of June 30, 2018, according to RSEG, there were approximately 26 horizontal rigs running in the DJ Basin. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the DJ Basin are prospective for four or more producing zones of economic horizontal development including the Niobrara A, B and C and Codell formations.

Williston Basin

The Williston Basin stretches from western North Dakota into eastern Montana with the majority of operator horizontal drilling activity located in Mountrail, Williams, and McKenzie Counties, North Dakota. As of

91

June 30, 2018, according to RSEG, there were approximately 51 horizontal rigs running in the Williston Basin. Based on our geologic and engineering interpretations as well as current operator delineation efforts, we believe our mineral and royalty interests are prospective for two or more producing zones of economic horizontal development including the Bakken and multiple Three Forks benches. The majority of our interests are located in Mountrail, Williams and McKenzie Counties with additional interests owned in Divide, Burke, Dunn, Billings and Stark Counties, North Dakota and Richland County, Montana.

Other Counties

Our other interests are comprised of mineral and royalty interests owned in Carter and Love Counties, Oklahoma in what we refer to as the Extended Woodford play in the Marietta and Ardmore Basins and in Bradford, Sullivan and Washington Counties, Pennsylvania in the Marcellus and Utica Shale plays. Our interests in Carter and Love Counties are largely being developed by Exxon Mobil Corporation through their operating subsidiary XTO Energy, which currently has four horizontal rigs operating in the area. Our interests in Pennsylvania are largely being developed by Range Resources Corporation and Chief Oil & Gas LLC.

For more detailed information about the basins and regions described above, please read “Business—Our Properties—Focus Areas.”

Prospective Undeveloped Horizontal Drilling Locations

We believe our production and free cash flow will grow through the drilling of the substantial undeveloped organic inventory of horizontal drilling locations located on our acreage. As of June 30, 2018, as reflected in our reserve report prepared by CG&A, we have identified 10,187 gross proved, probable and possible undeveloped horizontal drilling locations across our gross DSU acreage. Furthermore, we believe additional optionality is possible through the delineation of additional horizontal formations including the Wolfcamp D and Jo Mill in the Permian Basin and the SCORE in the SCOOP and STACK plays, which are not currently reflected in our reserve reports as well as downspacing in existing formations. Nearly 45% of our total net horizontal undeveloped locations are located in the Delaware and Midland Basins, with another 24% located in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma, as shown in the following table.

	Gross Horizontal Undeveloped Locations		Percentage of Total Portfolio			Net Horizontal Undeveloped Locations		Percentage of Total Portfolio
Delaware Basin		2,725		27	%		34.6		38	%
Midland Basin		626		6	%		6.0		7	%
SCOOP		1,036		10	%		6.9		7	%
STACK		1,697		17	%		15.6		17	%
DJ Basin		1,765		17	%		22.6		25	%
Williston		1,712		17	%		3.1		3	%
Other		626		6	%		3.2		3	%
Total		10,187		100	%		92.0		100	%

92

Additionally, the following table provides a detailed summary of our inventory of horizontal drilling locations as of June 30, 2018.

Productive Horizons	Gross Horizontal Undeveloped Locations(1)		Total Gross Horizontal Locations(2)		DSUs(3)(4)		Gross Horizontal Undeveloped Locations Per DSU(4)		Total Gross Horizontal Locations Per DSU(4)		Net Horizontal Undeveloped Locations(5)
Delaware Basin
Wolfcamp A		1,249		1,455		226		5.5		6.4		17.8
Wolfcamp B		525		569		172		3.1		3.3		8.7
3rd BS/WC XY		399		469		144		2.8		3.3		2.7
2nd Bone Spring		244		259		86		2.8		3.0		1.5
Avalon		118		129		50		2.4		2.6		0.6
Other		190		200		54		3.5		3.7		3.3
Total		2,725		3,081		226		12.1		13.6		34.6
Midland Basin
Wolfcamp A		156		191		53		2.9		3.6		1.5
Wolfcamp B		151		189		50		3.0		3.8		1.5
Lower Spraberry		234		250		53		4.4		4.7		2.1
Other		85		91		23		3.7		4.0		0.9
Total		626		721		53		11.8		13.6		6.0
SCOOP
Woodford		744		975		149		5.0		6.5		4.9
Springer		292		324		78		3.7		4.2		2.0
Total		1,036		1,299		149		7.0		8.7		6.9
STACK
Woodford		898		998		144		6.2		6.9		7.7
Meramec		799		912		116		6.9		7.9		7.9
Total		1,697		1,910		161		10.5		11.9		15.6
DJ Basin
Niobrara		1,302		1,992		184		7.1		10.8		16.8
Codell		463		655		138		3.4		4.7		5.8
Total		1,765		2,647		184		9.6		14.4		22.6
Williston Basin
Bakken		785		1,637		340		2.3		4.8		1.3
Three Forks		927		1,525		340		2.7		4.5		1.8
Total		1,712		3,162		343		5.0		9.2		3.1
Other		626		692		100		6.3		13.1		3.2
Grand Total		10,187		13,512		1,216		8.4		11.1		92.0

(1) Represents gross horizontal drilling locations across our gross DSU acreage.

(2) Includes all undeveloped and developed wells in each horizon.

(3) Represents the aggregate number of DSUs covering any of the applicable productive horizons as identified by CG&A.

(4) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU. (i.e., not all horizons are booked in all DSUs).

(5) A net well represents 100% net revenue interest in a single gross well.

93

Third-Party Operators

Beyond our technical analysis to identify core, highly economic areas, an additional critical aspect of our evaluation process is to acquire mineral and royalty interests that will be drilled and completed by operators we believe will outperform their peers through the application of the latest drilling and completion technologies in each of our operating basins. The following chart summarizes our exposure to these operators based on the percentage of our net interests in the wells to be drilled by each operator.

94

In addition, the following table shows our exposure to each of these operators broken down by our primary focus areas based on the percentage of our net interests in the wells to be drilled by each operator as of June 30, 2018.

	Percentage as of June 30, 2018
Operator	Total Portfolio		Delaware		Midland		SCOOP		STACK		DJ Basin		Williston		Other
Noble Energy		10%		16%		—		—		—		16%		—		—
Anadarko Petroleum		8%		13%		—		—		—		15%		—		—
Newfield Exploration		7%		—		—		25%		16%		—		3%		57%
Continental Resources		5%		—		—		47%		2%		—		16%		17%
XTO		4%		9%		1%		—		—		—		5%		16%
Devon Energy		4%		*		—		—		22%		—		—		—
Whiting Petroleum		3%		—		—		—		—		13%		4%		—
Marathon Oil		3%		—		—		16%		12%		—		2%		*
Pioneer Natural Resources		3%		—		50%		—		—		—		—		—
PDC Energy		3%		1%		—		—		—		10%		—		—
Extraction Oil and Gas		3%		—		—		—		—		11%		—		—
Cimarex Energy		3%		3%		—		—		10%		—		—		—
EOG Resources		3%		1%		—		*		—		9%		4%		—
Patriot Resources		2%		6%		—		—		—		—		—		—
Diamondback Energy(1)		2%		3%		13%		—		—		—		—		—
Chevron Corporation		2%		5%		—		—		—		—		—		—
Halcon Resources		2%		6%		—		—		—		—		2%		—
Concho Resources		2%		4%		*		—		—		—		—		—
BP(2)		2%		6%		—		—		—		—		—		—
Occidental Petroleum		1%		4%		1%		—		—		—		—		—
Subtotal		72%		75%		65%		88%		62%		74%		37%		90%
Other Operators		28%		25%		35%		12%		38%		26%		63%		10%
Total		100%		100%		100%		100%		100%		100%		100%		100%

Note: Individual amounts may not add up to totals due to rounding.

* Less than 1%.

(1) Pro forma for Diamondback Energy’s acquisition of Energen Resources Corporation.

(2) Pro forma for BP’s acquisition of BHP Billiton Ltd.’s U.S. shale business.

Business Strategies

Our primary business objective is to deliver an attractive risk-adjusted total return to our shareholders through (i) the growth of our free cash flow generated from our existing portfolio of approximately 61,219 net royalty acres, and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. We intend to accomplish this objective by executing the following strategies:

• Capture growth in free cash flow through continued development of our mineral and royalty interests. We have targeted assets in the core of highly economic, liquids-rich resource plays, and we expect operators to continue deploying rigs and capital to develop our existing mineral and royalty interests, even in low commodity price environments. As of June 30, 2018, there were 586 DUCs across our acreage position, representing 8% of the DUCs estimated by the EIA in the continental United States. We believe this DUC inventory will contribute to our near-term free cash flow growth as operators complete and turn these DUCs to sales. Further, we expect to generate future free cash flow growth from ongoing drilling and permitting activity on our interests. Since inception, our interests have been actively drilled, with a total of 2,739 producing horizontal wells on our gross DSU acreage over the period. Over the twelve months ended June 30, 2018, there were an average of 27 rigs deployed across our acreage, with an average of approximately 865 net mineral acres under development per month. Additionally, operators continue to actively permit our interests, with approximately 80 new gross drilling permits issued per

95

month over the last 12 months and a total of approximately 751 existing gross permitted drilling locations yet to be drilled across our gross DSU acreage as of June 30, 2018 (excluding Laramie County, Wyoming). As a result, we believe that our assets are positioned to provide substantial near- and long-term free cash flow growth without exposure to incremental capital expenditures or lease operating expenses associated with ongoing development.

• Target a portfolio in the core areas of highly economic liquids-rich resource plays under premier operators. Our growing portfolio is driven by our acquisition strategy focused on core positions in top-tier, high-return, liquids-rich resource plays that we believe will continue to attract development capital throughout commodity price cycles. Our targeted approach has led us to acquire mineral and royalty interests in 37 selected counties that we consider to be some of the most economically prospective in the country, with 59% of the entire horizontal rig fleet in the continental United States active within those counties as of June 30, 2018. Based on an assumed $6 million per well, we estimate that operators deployed approximately $44.3 billion in drilling and completion capital expenditures to those counties during 2017 and $2.1 billion in drilling and completion capital expenditures to our gross DSU acreage. We believe that our focus on acquiring assets in the core of resource plays will also help to mitigate any negative impact of possible future declines in oil and natural gas prices, as operators have historically continued to deploy rigs and capital to these core areas even in lower commodity price environments. As an example, had we owned our portfolio of 61,219 net royalty acres as of June 30, 2018 since January 1, 2013, we estimate that the pro forma production volumes net to our interests would have grown at an approximate 53% compound annual growth rate from the beginning of 2013 through June 30, 2018, despite average crude oil prices during the first half of 2018 decreasing by 33% compared to the year ended December 31, 2013.

• Leverage exploration and production technical expertise to evaluate acquisition opportunities. Our team’s technical expertise and extensive experience with exploration and production companies (i.e., operators) allows us to identify and acquire core mineral and royalty interests that we believe will be developed by premier operators. Our technical evaluation process for a potential mineral and royalty interest acquisition includes, but is not limited to, an evaluation of the following with respect to the associated mineral and royalty interests: (i) the existing producing wells, (ii) the number of productive formations anticipated to be developed, (iii) the number of wells anticipated to be developed per productive formation, (iv) the forecasted EURs of all wells per productive formation, (v) the oil and natural gas composition per productive formation and (vi) the anticipated performance of the operator expected to develop the interest. We analyze and estimate the economic returns of the operators to better understand the quality of the mineral interests relative to their other assets. We also evaluate operator performance relative to peers and formulate a drilling timeline, which is typically based on operator activity levels within a resource play and indications by that operator in public or regulatory filings regarding its future drilling and completion activities. As of June 30, 2018, we estimate that 75% of our undeveloped net wells will be drilled by operators who are currently running five or more rigs in the continental United States. If a potential transaction is comprised of multiple DSUs, we evaluate each DSU individually. We believe that acquiring mineral and royalty interests in core areas under top-performing, active operators enhances the probability that our undeveloped mineral and royalty interests will be converted to producing locations that will continue to generate free cash flow growth.

• Capitalize on strong acquisition sourcing network. Our team leverages its extensive network of acquisition sources, including contacts developed during the 20 years prior to our formation while working as exploration and production operators as well as those developed since our formation in 2012. Since inception, we have sourced and originated a significant number of potential transactions and, through our rigorous underwriting and evaluation process, closed 1,229 mineral and royalty transactions. We believe we have developed a reputation in the minerals industry as a responsive, efficient and reliable acquirer, which continues to provide us consistent transaction opportunities in each of our target basins. During 2017, we increased our mineral and royalty interests by 21% or 9,361 net royalty acres. During 2018, we closed our largest single acquisition to date for an aggregate purchase price of approximately

96

$41 million, subject to customary post-closing adjustments, consisting of mineral and royalty interests in the Delaware Basin in Loving County, Texas and Lea County, New Mexico, under highly active, premier operators. As a public entity, we will continue to source transactions in the most attractive areas based on our analysis, with the objective of becoming a premier consolidator of mineral and royalty interests in the United States.

• Maintain financial flexibility via conservative capital structure. We are committed to maintaining a conservative capital structure that will provide us with the financial flexibility to execute our acquisition strategy. Upon completion of this offering, we will have limited indebtedness and believe the proceeds from this offering, cash from operations, $60 million of available borrowings under our term loan facility and future potential access to the public capital markets will provide us with sufficient liquidity and financial flexibility to execute accretive acquisitions to further grow our production and free cash flow.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and to achieve our primary business objectives:

• Experienced, technically focused team with significant mineral and royalty interest acquisition history and value-creation track record. Our management team has a proven track record of driving total return for shareholders, including sourcing opportunities, executing accretive acquisitions, maximizing asset development and monetizing assets. We have assembled a team of over 25 dedicated professionals, including a technical staff comprised of nine full-time, highly experienced geologists and reservoir engineers who apply a methodical evaluation approach focused on the same criteria as would an operator, while maintaining long-term disciplined underwriting criteria to target transactions in the core areas of liquids-rich resource basins. Our portfolio has been assembled over the past six years through the completion of over 1,229 transactions. Through June 30, 2018, our team has assembled 61,219 net royalty acres in the core areas of premier, liquids-rich resource plays, and we intend to continue being an active acquirer of mineral and royalty interests in the future. We believe our team’s track record of success is exemplified by the historical value that has been created for public and private shareholders of both Brigham Exploration and Brigham Operating through the early-stage identification, acquisition and monetization of positions in liquids-rich resource plays in the Williston Basin and Southern Delaware in the Permian Basin, ultimately resulting in the sale of Brigham Exploration’s and Brigham Operating’s assets for an aggregate of $7.0 billion. Furthermore, during its time as a public company, Brigham Exploration’s enterprise value grew from $117.5 million at the time of its initial public offering to its eventual sale to Statoil for $4.4 billion.

• Minerals and royalties are a perpetual asset class unburdened by both development capital expenditures and lease operating expenses, thereby driving significant free cash flow. Our mineral interests are a perpetual right to a fixed percentage of royalty revenues from the oil, natural gas and NGLs extracted from our interests. As a mineral and royalty owner, we do not incur any of the capital commitments related to drilling the undeveloped horizontal inventory on our interests, the ongoing lease operating expenses as minerals on our acreage are produced or the potential environmental or operational liabilities related to maintaining oil, natural gas and NGL production, including workovers and other well remediation and abandonment costs. As a result, we benefit from organic free cash flow growth associated with our mineral and royalty interests and believe that we realize higher margins over time with less exposure to risks than an exploration and production company. Finally, due to the perpetual nature of our mineral interests and the lack of future development costs, we benefit from: (i) the development of additional producing formations underlying our interests as operators delineate different horizons, (ii) the drilling of additional wells per producing formation as operators determine optimal well spacing, (iii) improved EURs as operators continuously improve drilling and completion techniques, and (iv) incremental lease bonus payments when we have the opportunity to lease existing open acreage or to re-lease acreage that has expired or is not held by production under the terms of our leases.

97

• Multi-year drilling inventory in the core of four active liquids-rich resource basins. As of June 30, 2018, we had interests in approximately 2,739 producing horizontal wells across 1,216 identified DSUs, or an average of 2.3 producing horizontal wells per DSU, as reflected in our reserve report prepared by CG&A. As reflected in that same reserve report, 10,187 horizontal drilling locations are yet to be drilled by operators across those 1,216 DSUs, which we believe will drive future free cash flow growth. These undeveloped horizontal drilling locations are located across (i) four liquids-rich, target basins including the Permian, SCOOP/STACK plays in the Anadarko, DJ and Williston; (ii) a diverse portfolio of operators including Noble, Anadarko, Newfield and Continental; and (iii) a number of productive formations including the Wolfcamp, Bone Spring, Avalon, Woodford, Springer, Meramec, Niobrara, Codell, Bakken and Three Forks benches. In addition, we expect operators will continue to delineate additional geologic zones and optimize well spacing across our acreage, leading to incremental locations that we do not currently include in our inventory.

• Portfolio of high-quality operators developing our position. We expect our mineral and royalty interests to be converted from undeveloped to producing by a portfolio of high-quality operators who deploy the latest drilling and completion technologies and have significant access to capital, including Noble, Anadarko, Newfield and Continental, as well as other best-in-class operators throughout our core areas. As of June 30, 2018, we have exposure to the top three operators by permit, drilling activity and gross operated production in each of the plays in which our mineral and royalty interests are located. As of June 30, 2018, we estimate that 75% of our undeveloped net wells will be drilled by operators who are currently running five or more rigs in the continental United States. Because of our exposure to the most active operators within the core of each of our basins, we believe that capital will continue to be deployed in low commodity price environments to convert our drilling inventory into producing locations, thereby increasing our free cash flow.

Oil, Natural Gas and NGLs Data

Proved, Probable and Possible Reserves

Evaluation and Audit of Proved, Probable and Possible Reserves. Our proved, probable and possible reserve estimates as of June 30, 2018 and December 31, 2017 and 2016 were prepared by CG&A, our independent petroleum engineers. Within CG&A, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve reports incorporated herein is Todd Brooker. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers (SPEE).

Mr. Brooker meets or exceeds the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Summaries of CG&A’s reports with respect to our proved, probable and possible reserve estimates as of June 30, 2018 and December 31, 2017 and 2016 are included as exhibits to the registration statement of which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate

98

our proved, probable and possible reserves relating to our properties. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved, probable and possible reserve report to discuss the assumptions and methods used in the proved, probable and possible reserve estimation process. We provide historical information to CG&A for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and our estimates of our operators’ operating and development costs. Hal Hogsett is primarily responsible for overseeing the preparation of our reserve estimates. Mr. Hogsett has substantial reservoir and operations experience having worked as a petroleum engineer since 2009 and is supported by our engineering and geoscience staff. Prior to joining our Company in 2017, Mr. Hogsett worked at Apache Corporation and Antero Resources Corporation.

The preparation of our proved, probable and possible reserve estimates were completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

• review and verification of historical production data, which data is based on actual production as reported by our operators;

• review by Hal Hogsett, our Vice President of Reservoir Engineering of all of our reported proved, probable and possible reserves, including the review of all significant reserve changes and all new PUDs additions;

• verification of property ownership by our land department;

• review of reserve estimates by Mr. Hogsett or under his direct supervision; and

• direct reporting responsibilities by Mr. Hogsett to our Chief Executive Officer.

Estimation of Proved Reserves. In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, 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. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves as of June 30, 2018 and December 31, 2017 and 2016 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

99

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

Estimation of Probable Reserves. Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. All of our probable reserves as of June 30, 2018 and December 31, 2017 and 2016 were estimated using a deterministic method, which involves two distinct determinations: an estimation of the quantities of recoverable oil and natural gas and an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of probable reserves, the recoverable reserves cannot be said to have a “high degree of confidence that the quantities will be recovered”, but are “as likely as not to be recovered.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over one mile but under three miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our probable reserves came from a combination of these factors depending upon the applicable basin. Many of the probable locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other probable locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book probable locations if there was geologic uncertainty or if there was not commercial production to support such locations.

Estimation of Possible Reserves. Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. All of our possible reserves as of June 30, 2018 and December 31,

100

2017 and 2016 were estimated using a deterministic method, which involves two distinct determinations: an estimation of the quantities of recoverable oil and natural gas and an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of possible reserves, the recoverable reserves cannot be said to be “as likely as not to be recovered”, but “might be achieved, but only under more favorable circumstances than are likely.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the possible location of over one mile but under five miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our possible reserves came from a combination of these factors depending upon the applicable basin. Many of the possible locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other possible locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book possible locations if there was geologic uncertainty or if there was not commercial production to support such location.

Summary of Reserves. The following table presents our estimated net proved, probable and possible reserves as of June 30, 2018 and December 31, 2017 and 2016, based on our proved, probable and possible reserve estimates as of such dates, which have been prepared by CG&A, our independent petroleum engineering firm, and prepared in accordance with the rules and regulations of the SEC. All of our proved, probable and possible reserves are located in the United States.

	June 30, 2018(1)		December 31, 2017(2)		December 31, 2016(3)
Estimated proved developed reserves:
Oil (MBbls)		3,844		2,804		1,772
Natural gas (MMcf)		15,424		13,028		6,077
NGLs (MBbls)		1,427		1,185		628
Total (MBoe)		7,842		6,160		3,413
Estimated proved undeveloped reserves:
Oil (MBbls)		6,271		5,920		5,402
Natural gas (MMcf)		25,315		25,373		16,914
NGLs (MBbls)		2,826		2,795		1,728
Total (MBoe)		13,316		12,944		9,950
Estimated proved reserves:
Oil (MBbls)		10,115		8,724		7,174
Natural gas (MMcf)		40,739		38,401		22,991
NGLs (MBbls)		4,254		3,980		2,356
Total (MBoe)		21,159		19,104		13,363
Estimated probable reserves:
Oil (MBbls)(4)		13,478		11,882		10,825
Natural gas (MMcf)(4)		56,506		47,659		30,193
NGLs (MBbls)(4)		6,716		5,654		3,328
Total (MBoe)(4)		29,612		25,479		19,185
Estimated possible reserves:
Oil (MBbls)(4)		8,861		7,426		7,598
Natural gas (MMcf)(4)		22,803		21,846		14,744
NGLs (MBbls)(4)		3,218		2,738		1,946
Total (MBoe)(4)		15,880		13,805		12,001
Oil and Natural Gas Prices:
Oil—WTI posted price per Bbl	$	57.52	$	51.34	$	42.60
Natural gas—Henry Hub spot price per Mcf	$	2.91	$	2.99	$	2.47

101

(1) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $57.52 per barrel as of June 30, 2018 was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 24% to 43% of the WTI posted price. For gas volumes, the average Henry Hub spot price of $2.91 per MMBtu as of June 30, 2018 was adjusted for energy content, transportation fees and a regional price differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $54.50 per barrel of oil, $21.29 per barrel of NGL and $2.44 per Mcf of gas as of June 30, 2018.

(2) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $51.34 per barrel as of December 31, 2017 was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 19% to 42% of the WTI posted price. For gas volumes, the average Henry Hub spot price of $2.99 per MMBtu as of December 31, 2017 was adjusted for energy content, transportation fees and a regional price differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $48.88 per barrel of oil, $19.00 per barrel of NGL and $2.93 per Mcf of gas as of December 31, 2017.

(3) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $42.60 per barrel as of December 31, 2016 was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 7% to 33% of the WTI posted price. For gas volumes, the average Henry Hub spot price of $2.47 per MMBtu as of December 31, 2016 was adjusted for energy content, transportation fees and a regional price differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $36.04 per barrel of oil, $12.78 per barrel of NGLs and $2.40 per Mcf of gas as of December 31, 2016.

(4) All of our estimated probable and possible reserves are classified as undeveloped.

Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors.”

Additional information regarding our proved, probable and possible reserves can be found in the notes to our financial statements included elsewhere in this prospectus and the proved, probable and possible reserve reports as of June 30, 2018 and December 31, 2017 and 2016, which are included as exhibits to the registration statement of which this prospectus forms a part.

PUDs

As of June 30, 2018, we estimated our PUD reserves to be 6,271 MBbls of oil, 25,315 MMcf of natural gas and 2,826 MBbls of NGLs, for a total of 13,316 MBoe. As of December 31, 2017, we estimated our PUD reserves to be 5,920 MBbls of oil, 25,373 MMcf of natural gas and 2,795 MBbls of NGLs, for a total of 12,944 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

102

The following tables summarize our changes in PUDs during the year ended December 31, 2017 and the six months ended June 30, 2018 (in MBoe):

	Proved Undeveloped Reserves
	(unaudited)
Balance, December 31, 2016		9,950
Acquisitions of reserves		2,442
Extensions and discoveries		3,057
Divestiture of minerals in place		(1,238	)
Revisions of previous estimates		284
Transfers to estimated proved developed		(1,551	)
Balance, December 31, 2017		12,944
Acquisitions of reserves		2,527
Extensions and discoveries		540
Revisions of previous estimates		(1,876	)
Transfers to estimated proved developed		(819	)
Balance, June 30, 2018		13,316

Changes in PUDs that occurred during 2017 were primarily due to:

• the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 2,442 MBoe of additional PUDs;

• well additions, extensions and discoveries of approximately 3,057 MBoe, as 547 horizontal well locations were converted from probable and possible to proved undeveloped, due to continuous activity and delineation of additional zones on our mineral and royalty interests;

• the divestiture of 1,238 MBoe through one sale of mineral and royalty interests located in the Permian Basin;

• the conversion of approximately 1,551 MBoe in PUD reserves into proved developed reserves as 156 horizontal locations were drilled; and

• positive volume revisions of 1,651 MBoe attributable to increased recovery in close proximity to our mineral and royalty interests, partially offset by negative revisions of approximately 1,367 MBoe in PUDs, of which 940 MBoe was due to development configuration and well spacing changes on our DJ Basin acreage by our operators and 427 MBoe was due to operator development timing adjustments.

Changes in PUDs that occurred during the first six months of 2018 were primarily due to:

• the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 2,527 MBoe of additional PUDs;

• well additions, extensions and discoveries of approximately 540 MBoe, as 113 horizontal well locations were converted from probable and possible to proved undeveloped, due to continuous activity and delineation of additional zones on our mineral and royalty interests;

• the conversion of approximately 819 MBoe in PUD reserves into proved developed reserves as 161 horizontal locations were drilled; and

• negative revisions of approximately 1,855 MBoe in PUDs attributable to development timing and EUR adjustments, and negative revisions of an additional 796 MBoe associated with NPRI burdens and DSU configurations. These negative revisions were partially offset by positive revisions of approximately 775 MBoe in PUDs attributable to continuous development in close proximity to our mineral and royalty interests as well as drilling spacing unit configuration adjustments.

103

As a mineral and royalty interests owner, we do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the operator. As a result, during the twelve months ended December 31, 2017 and the six months ended June 30, 2018, we did not have any expenditures to convert PUDs to proved developed reserves.

We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU formation and current well spacing information derived from state agencies and the operations of the exploration and production companies drilling our mineral and royalty interests. We generally do not have evidence of approval of our operators’ development plans, however we use a deterministic approach to define and allocate locations to proved reserves. While many of our locations qualify as geologic PUDs, we limit our PUDs to the quantities of oil and gas that are reasonably certain to be recovered in the next five years. As of June 30, 2018 and December 31, 2017, approximately 63% and 66%, respectively, of our total proved reserves were classified as PUDs.

Oil, Natural Gas and NGL Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

	Our Predecessor
	Six Months Ended June 30,				Year Ended December 31,
	2018		2017		2017		2016
Production data:
Oil (MBbls)		332		186		454		262
Natural gas (MMcf)		1,172		771		1,768		955
NGLs (MMBbls)		104		33		109		90
Total (MBoe)(1)(2)		631		348		858		512
Average realized prices(3):
Oil (per Bbl)	$	61.61	$	46.81	$	48.61	$	39.04
Natural gas (per Mcf)		2.82		3.53		3.11		2.53
NGLs (per Bbl)		25.17		17.99		22.71		15.25
Total (per Boe)(2)	$	41.79	$	34.59	$	35.02	$	27.43
Average costs (per Boe):
Gathering, transportation, and marketing expenses	$	3.18	$	1.92	$	2.04	$	1.60
Severance and ad valorem taxes		2.60		1.72		1.87		1.23
Depreciation, depletion and amortization		9.12		8.95		8.10		9.60
General and administrative expenses(4)		4.41		5.26		4.59		7.32
Interest and related fees		1.78		0.43		0.65		0.58
Loss on derivative instruments, net		1.45		—		0.14		—
Total	$	22.54	$	18.28	$	17.39	$	20.33

(1) May not sum or recalculate due to rounding.

(2) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

(3) Excludes the effect of commodity derivative instruments.

(4) General and administrative expenses do not include additional expenses we would have to incur as a result of being a public company.

104

Productive Wells

Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of June 30, 2018, we owned mineral and royalty interests in 2,739 gross productive horizontal wells, which consisted of 2,511 oil wells and 228 natural gas wells.

We do not own any working interests in any wells. Accordingly, we do not own any net wells as such term is defined by Item 1208(c)(2) of Regulation S-K.

Acreage

The following table sets forth information relating to our acreage for our mineral and royalty interests as of June 30, 2018:

Basin	Gross DSU Acreage		Net Royalty Acreage		100% Royalty Acreage
Delaware		179,383		16,691		2,086
Midland		49,938		2,659		332
SCOOP		161,247		7,777		972
STACK		159,970		8,373		1,047
DJ		160,897		15,224		1,903
Williston		471,685		6,747		843
Other		77,230		3,748		469
Total		1,260,350		61,219		7,652

The vast majority of our mineral and royalty interests are leased to our operators with 71% of our 55,868 leased net royalty acres being held by production as of June 30, 2018. In addition, we had 5,351 net royalty acres that were not leased as of June 30, 2018.

Drilling Results

The following table sets forth information with respect to the number of wells turned to production on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. As a mineral and royalty interest owner, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory.

	For the Year Ended December 31,
	2015		2016		2017
Development wells:
Productive		513		277		547
Dry(1)		—		—		—
Total		513		277		547

(1) We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.

As of December 31, 2017, we had 495 wells on our properties in the process of drilling, completing or dewatering, or shut in awaiting infrastructure, that are not reflected in the above table.

105

Regulation of Environmental and Occupational Safety and Health Matters

Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:

• obtain permits to conduct regulated activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

• restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

• initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

• apply specific health and safety criteria addressing worker protection; and

• impose substantial liabilities for pollution resulting from operations.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to our operators of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties are subject.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

106

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes generated. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil, natural gas and NGL drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil, natural gas and NGL wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil, natural gas and NGL wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes rulemaking for revised oil and natural gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any such change could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of our operators’ operations.

Certain of our properties have been used for oil and natural gas exploration and production for many years. Although the operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under our properties, or on or under other offsite locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. Our properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

Water Discharges and NORM

The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Obtaining permits has the potential to delay the development of oil and natural gas projects. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.

107

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require our operators to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, in June 2016 the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Any such requirements could increase the costs of development and production on our properties, potentially impairing the economic development of our properties. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operators’ operations and restrict or delay their ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include gathering and boosting facilities.

Furthermore, in June 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category. However, over the past year the EPA has taken several steps to delay implementation of the June 2016 methane rule, and the agency proposed a separate rulemaking in June 2017 to stay the methane requirements for a period of two years and revisit implementation of the standards in their entirety. In September 2018, the EPA proposed amendments to the standards, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency. As a result of these developments, substantial uncertainty exists with respect to the future implementation of the EPA’s methane rules.

The U.S. Congress has not considered adopting federal legislation to reduce GHG emissions in recent years. In the absence of such federal climate change legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Other states have passed renewable energy mandates, and recently automakers have announced their intention to increase production of electric powered vehicles in response to concerns related to climate change. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions, known as the Paris Treaty. The Paris Treaty entered into force in November 2016. In August 2017, however, the U.S. State Department informed the United Nations that the United States plans to withdraw from the Paris Treaty, but may later pursue negotiations either to reenter the Paris Treaty on different terms or establish a new framework. The Paris Treaty provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our properties, any such future laws and regulations imposing

108

reporting obligations or limitations on emissions of GHGs could require the operators of our properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition. Such requirements could also adversely affect demand for the oil, natural gas and NGLs produced, all of which could reduce production attributable to our properties and our results of operations.

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could adversely impact the development of our properties and our results of operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could require the operators of our properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Hydraulic Fracturing Activities

A substantial portion of the production on our properties involved the use of hydraulic fracturing techniques. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production.

Hydraulic fracturing typically is regulated by state oil and natural gas commissions or similar agencies, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued permitting guidance that applies to such activities. Additionally, the EPA issued final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions of methane and VOCs released during hydraulic fracturing and separately published in June 2016 an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In September 2018, the EPA proposed amendments to its methane standards, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For

109

example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil, natural gas and NGL exploration and production activities and, therefore, adversely affect the development of our properties.

Endangered Species Act

The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause our operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes the Permian Basin, and to reconsider listing the species under the ESA. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Title to Properties

Prior to completing an acquisition of mineral and royalty interests, we perform a title review on each tract to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens. For our Texas properties, we obtain a limited title memorandum rendered by an oil and gas law firm. As a result, title examinations have been obtained on a significant portion of our properties.

In addition to our initial title work, operators often will conduct a thorough title examination prior to leasing and/or drilling a well. Should an operator’s title work uncover any further title defects, either we or the operator will perform curative work with respect to such defects. An operator generally will not commence drilling operations on a property until any material title defects on such property have been cured.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of oil and gas interests, non-participating royalty interests and other burdens, easements, restrictions or minor encumbrances customary in the oil and natural gas industry, we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.

110

Competition

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases and personnel required to find and produce reserves. Many of our competitors not only own and acquire mineral and royalty interests but also explore for and produce oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Additionally, some of the areas in which our properties are located are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our operators may be unable to move their equipment between locations, thereby reducing their ability to operate our wells, reducing the amount of oil and natural gas produced from the wells on our properties during such times. Additionally, extended drought conditions in the areas in which our properties are located could impact our operators’ ability to source sufficient water or increase the cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Employees

As of June 30, 2018, we had 25 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory. Please see “Executive Compensation—Narrative Disclosure to Summary Compensation Table” for a discussion regarding the entity that has historically employed our employees.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.

111

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

112

MANAGEMENT

The following table sets forth the names, ages and titles of our directors and executive officers.

Name	Age	Position
Ben “Bud” M. Brigham	58	Executive Chairman
Robert M. Roosa.	48	Chief Executive Officer and Director
Blake C. Williams	31	Chief Financial Officer
Harold D. Carter	79	Director
John A. Holland	36	Director
W. Howard Keenan, Jr.	67	Director
James R. Levy	42	Director
Richard Stoneburner	64	Director
John R. Sult	59	Director

The following table sets forth the names, ages and titles of certain of our other key employees.

Name	Age	Position
Geoff Boyd	36	Vice President of Acquisitions
S. Bradley Burris	39	Vice President of Land
Hamilton W. Hogsett	31	Vice President of Reservoir Engineering
Kevin J. L’abbé	37	Vice President of Exploration
A. Dax McDavid	38	Vice President of Exploration
Jordan K. Spearman	34	Vice President of Business Development

Set forth below is a description of the backgrounds of our directors, executive officers and other key employees. Unless otherwise indicated, references to positions held at Brigham Minerals or our company include positions held at Brigham LLC, Brigham Resources and/or Brigham Minerals, LLC.

Directors and Executive Officers

Ben “Bud” M. Brigham—Executive Chairman. Ben “Bud” M. Brigham is our founder and has served as our executive chairman since our inception in November 2012. In addition to founding our company in 2012, Mr. Brigham founded Brigham Operating in 2012 and served as its chairman until the sale of substantially all of its asset to Diamondback Energy, Inc. in February 2017. Mr. Brigham also founded Atlas Permian Sand, LLC in 2017, Brigham Development, LLC in 2013 and Anthem Ventures, LLC in 2011. Prior to such time, Mr. Brigham founded Brigham Exploration Company in 2017 (the second entity founded by Mr. Brigham with such name) to pursue non-operated interests in the Permian Basin. Mr. Brigham formed the initial Brigham Exploration in 1990 and served as its President, Chief Executive Officer and Chairman of the Board until its sale to Statoil in December 2011. Prior to founding Brigham Exploration in 1990, Mr. Brigham served for six years as an exploration geophysicist with Rosewood Resources, and as a seismic data processing geophysicist for Western Geophysical. Mr. Brigham earned a Bachelor of Science in Geophysics from the University of Texas. Mr. Brigham has served on the National Petroleum Council, the American Association of Petroleum Geologists, the Society of Exploration Geophysicists, the Independent Producers Association of America, the Society of Independent Professional Earth Scientists and The Bureau of Economic Geology Visiting Committee. Mr. Brigham was inducted into the All American Wildcatters in April 2012 and the University of Texas Chancellor’s Council Executive Committee in April 2015. Mr. Brigham was selected to serve on our board of directors due to his knowledge of the industry and leadership of our company since its inception.

Robert M. Roosa—Chief Executive Officer and Director. Robert M. Roosa has served as our President since our inception in November 2012, as our Chief Executive Officer since July 2017 and as a director of our company since May 2018. Mr. Roosa served as the President of Anthem Ventures and assisted Mr. Brigham with

113

a number of family ventures between January 2012 and January 2017. Mr. Roosa served various roles, including Director of Finance and Investor Relations, while at Brigham Exploration from 2006 until its sale to Statoil in December of 2011. From 2000 to 2006, Mr. Roosa held a series of positions at Exxon Mobil Corporation in the Corporate Treasurer’s Department. Prior to 2000, Mr. Roosa worked for Cooper Industries in its Corporate Controllers and Audit Groups and with Deloitte & Touche LLP in its audit function. Mr. Roosa graduated from Southern Methodist University with a Master of Business Administration in 2000 and from The University of Texas at Austin with a Bachelors of Business Administration in 1992. Mr. Roosa was selected to serve on our board of directors due to his knowledge of the industry and leadership of our company since its inception.

Blake C. Williams—Chief Financial Officer. Blake C. Williams has served as our Chief Financial Officer since July 2017. Mr. Williams previously served as Director of Finance and Marketing for Brigham Operating from January 2015 to June 2017 and as Corporate Finance Associate from January 2013 to December 2014. He was responsible for all aspects of corporate finance, including capital budgeting, financial analysis and acquisition evaluation, as well as midstream strategy and marketing. From 2008 to 2012, Mr. Williams was a natural gas trader and scheduler at Vega Energy, an asset management and consulting firm that works with customers in the natural gas distribution and storage sectors. Mr. Williams earned a Bachelor of Arts in Economics from Texas A&M University and a Master of Business Administration from the McCombs School of Business at the University of Texas at Austin.

Harold D. Carter—Director. Harold D. Carter has served as a director of our company since 2013. Mr. Carter has over 50 years of oil and gas industry experience and has been an independent consultant since 1990. Prior to consulting, Mr. Carter served as Executive Vice President of Pacific Enterprises Oil Company (USA). Before that, Mr. Carter was employed for 20 years by Sabine Corporation, ultimately serving as President and Chief Operating Officer from 1986 to 1989. Mr. Carter was a founding partner in Brigham Exploration and was a director from 1997 until 2011 when the company was sold to Statoil. Mr. Carter is a director of Abraxas Petroleum Corporation (NASDAQ: AXAS) and Longview Energy Company, a private exploration and production company. He currently is Vice Chairman of the Board of Trustees of The Texas Scottish Rite Hospital for Children. Also, he is a former President of the American Association of Professional Landmen and the Dallas Petroleum Club. He received a Bachelor of Business Administration in Petroleum Land Management from The University of Texas at Austin and completed the Program for Management Development at the Harvard University Business School. Mr. Carter was selected to serve on our board of directors in light of his energy industry knowledge.

John A. Holland—Director. John A. Holland has served as a director of our company since August 2018. Mr. Holland joined Warburg Pincus in 2010 and is currently a Principal in the energy group. He is a director of Hawkwood Energy, Rubicon Oilfield International, Conquest Completion Services and ATX Energy Partners. Prior to joining Warburg Pincus, he worked as an investment professional at GTCR, a middle-market private equity firm, and as an analyst at UBS Investment Bank. Mr. Holland holds an A.B. in economics with honors from the University of Chicago and a Master of Business Administration from the Stanford Graduate School of Business. Mr. Holland was selected to serve on our board of directors in light of his financial and energy industry knowledge.

W. Howard Keenan, Jr.—Director. W. Howard Keenan, Jr. has served as a director of our company since April 2013. Mr. Keenan has over 40 years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private investment manager focused on the energy industry. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners fund in 1991. Mr. Keenan also serves on the Boards of Directors of the following public companies: Antero Resources Corporation (NYSE: AR), Antero Midstream Partners LP (NYSE: AM), Antero Midstream GP LP (NYSE: AMGP), Ramaco Resources, Inc. (NYSE: METC) and Solaris Oilfield Infrastructure, Inc. (NYSE: SOI). In addition, he is serving or has served as a director of multiple Yorktown Partners portfolio companies. Mr. Keenan holds a Bachelor of Arts degree cum laude from Harvard College and a Master of Business Administration degree from Harvard

114

University. Mr. Keenan was selected to serve on our board of directors in light of his financial and energy industry knowledge.

James R. Levy—Director. James R. Levy has served as a director of our company since 2013. Mr. Levy joined Warburg Pincus in 2006 and is currently a Managing Director in the energy group. Previously, he worked at Kohlberg & Company, a middle-market private equity investment firm, and Wasserstein Perella & Co. He is a director of Antero Resources Corporation (NYSE: AR), Antero Midstream GP LP (NYSE: AMGP), ATX Energy Partners, LLC, Chisholm Energy Holdings, LLC, Citizen Energy Holdings, LLC, Hawkwood Energy, LLC, Independence Resources Management, LLC, Laredo Petroleum Inc. (NYSE: LPI) and Terra Energy Partners LLC. Additionally, he is a Trustee of Prep for Prep. Mr. Levy received a Bachelor of Arts in history from Yale University. Mr. Levy was selected to serve on our board of directors in light of his finance skills and energy industry knowledge.

Richard Stoneburner—Director. Richard Stoneburner has served as a director of our company since May 2018. Mr. Stoneburner joined Pine Brook in April 2013 and is a managing director on the energy investment team. Mr. Stoneburner represents Pine Brook as a director of Accelerate Resources Holdings, LLC, Pursuit Oil & Gas, LLC, Red Bluff Resources, LLC and Sagauro Resources, LLC. Mr. Stoneburner has over 41 years of experience in the oil and gas industry. He served as president of the North America Shale Production Division for BHP Billiton Petroleum from 2011 to 2012. From 2009 to 2011, Mr. Stoneburner served as president and chief operating officer of Petrohawk Energy Corporation. He was also its chief operating officer from 2007 to 2009 and led their exploration activities as vice president and then executive vice president of exploration from 2003 to 2007. Mr. Stoneburner began his career as a geologist in 1977 and held positions at Texas Oil and Gas Corp., Weber Energy Corp., Hugoton Energy Corp. and 3TEC Energy Corp. Mr. Stoneburner is on the board of directors of Yuma Exploration and Production Company, Inc. and Tamboran Resources Limited and is an advisor to Ayata. He also serves on the advisory council of The Jackson School of Geosciences at the University of Texas at Austin, on the visiting committee of the Bureau of Economic Geology at the University of Texas at Austin, is a board member of Switch Energy Alliance and Memorial Assistance Ministries. He is also President and a board member of the Houston Producers Forum. Mr. Stoneburner holds a B.S. in Geological Sciences from the University of Texas at Austin and an M.S. in Geological Sciences from Wichita State University. Mr. Stoneburner was selected to serve on our board of directors in light of his energy industry knowledge.

John R. “J.R.” Sult—Director. J.R. Sult has served as a director of our company since May 2018. Since August 2016, Mr. Sult has served on several public company boards as described below and has continued to evaluate additional potential opportunities. Mr. Sult served as Executive Vice President and Chief Financial Officer of Marathon Oil Corporation from September 2013 until August 2016. He was Executive Vice President and Chief Financial Officer of El Paso Corporation (“El Paso”) from March 2010 until May 2012 where he previously served as Senior Vice President and Chief Financial Officer from November 2009 until March 2010, and as Senior Vice President and Controller from November 2005 until November 2009. During the period from May 2012 to October 2012, Mr. Sult evaluated additional potential opportunities. Mr. Sult also served as Executive Vice President, Chief Financial Officer and director of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P., from July 2010 until May 2012, where he previously served as Senior Vice President and Chief Financial Officer from November 2009 until July 2010, and as Senior Vice President, Chief Financial Officer and Controller from August 2007 until November 2009. Mr. Sult also served as Chief Accounting Officer of El Paso and as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Prior to joining El Paso, Mr. Sult served as Vice President and Controller of Halliburton Energy Services from August 2004 until October 2005. Prior to joining Halliburton, Mr. Sult managed an independent consulting practice that provided a broad range of finance and accounting advisory services and assistance to public companies in the energy industry. Prior to private practice, Mr. Sult was an audit partner with Arthur Andersen LLP. He graduated from Washington & Lee University with a B.S. with Special Attainments in Commerce.

115

Mr. Sult joined the board of directors of Dynegy, Inc. in October 2012, where he served as audit committee chairman and joined the board of directors of Vistra Energy Corp. (NYSE: VST) in April 2018 in connection with its merger with Dynegy, Inc. Mr. Sult has also served on the Board of Directors of Jagged Peak Energy Inc. (NYSE: JAG) since January 2017 and serves as the chairman of its audit committee.

We believe that Mr. Sult, through his experience in executive financial positions with large public companies, brings significant knowledge of accounting, capital structures, finance, financial reporting, strategic planning and forecasting to our Board. In addition, Mr. Sult’s qualification as an “audit committee financial expert” provides an essential skill set relevant to his service on our board of directors and as the chairman of our audit committee.

Other Key Employees

Geoff Boyd—Vice President of Acquisitions. Geoff Boyd has served as our Vice President of Acquisitions since February 2012. Before joining our company in 2012, Mr. Boyd served as Vice President of Acquisitions at Bridgepoint Minerals for four years. He has experience purchasing mineral and royalty interests in oil and liquids-rich resource plays across the United States. Mr. Boyd graduated from The University of North Carolina with a Bachelor of Arts in Economics in 2005.

S. Bradley Burris—Vice President of Land. Brad Burris has served as our Vice President of Land since September 2018, as our Land Manager from January 2017 to September 2018 and as our Senior Landman from September 2016 to January 2017. Prior to joining our company, Mr. Burris served as a Senior Landman from January 2011 to August 2016 and as a Landman from June 2010 to December 2010 at Hilcorp Energy Company, working in the Eagle Ford shale, the Utica shale and conventional plays in both East and South Texas. Mr. Burris’s career began at BP America Production Company in January 2006 where he served as Land Negotiator. Mr. Burris earned a Bachelor of Science in Industrial Engineering with a minor in Mathematics, cum laude, from Texas A&M University and a Doctor of Jurisprudence from The University of Texas School of Law.

Hamilton (Hal) W. Hogsett—Vice President of Reservoir Engineering. Hal Hogsett has served as our Vice President of Reservoir Engineering since September 2018. Mr. Hogsett previously was our Reservoir Engineering Manager from September 2017 to July 2018 after relocating in August 2017 to join our company. Before joining our company, Mr. Hogsett served in various reservoir engineering roles with Antero Resources Corporation from March 2012 to July 2017 and in various engineering capacities with Apache Corporation from June 2009 to March 2012. Mr. Hogsett graduated from the University of Texas with a Bachelor of Science in Petroleum Engineering.

Kevin J. L’abbé—Vice President of Exploration. Kevin L’abbé has served as our Vice President of Exploration for the Mid-Continent and Rocky Mountain regions since September 2018. He previously served as our Exploration Manager from January 2017 to September 2018. He joined our company as a Geologist in October 2012. Mr. L’abbé’s previous experience includes a position as Exploration and Development Geologist with Petro-Harvester Oil & Gas LLC from 2011 to 2012 and as Exploration Geologist with Marion Energy Inc. from 2006 to 2011. Mr. L’abbé earned a Bachelor of Arts in Geology from the University of Texas.

A. Dax McDavid—Vice President of Exploration. A. Dax McDavid has served as our Vice President of Exploration for the Permian and Williston Basins since September 2018. He previously served as our Exploration Manager from January 2017 to September 2018 and as a Geologist from February 2013 to January 2017. Mr. McDavid began his career in 2003 as a Geologist for Stalker Energy, L.P., an independent onshore exploration and development company, working conventional plays across South Texas and the Gulf Coast. Mr. McDavid earned both a Bachelor of Arts and a Master of Arts in Geology from the University of Texas.

Jordan K. Spearman—Vice President of Business Development. Jordan Spearman has served as our Vice President of Business Development since September 2018 and as our Business Development Manager since

116

March 2017. He previously served as a landman for our company from September 2013 to March 2017. His prior experience includes founding and operating Bar S Oil & Gas, LLC, a land brokerage firm serving both the Permian Basin and Eagle Ford shale, in September 2013. He held a position as Land Negotiator from 2008 to 2009 at Anadarko Petroleum Corporation. Mr. Spearman graduated from Texas Tech University with a Bachelor of Business Administration in Energy Commerce with an emphasis in Petroleum Land Management.

Board of Directors

Upon the closing of this offering, it is anticipated that we will have eight directors, and we plan to appoint one additional director within one year of the listing of our common stock on the NYSE.

In connection with this offering, we will enter into a stockholders’ agreement with each of the Sponsors. The stockholders’ agreement is expected to provide the Sponsors with the right to designate a certain number of nominees to our board of directors so long as the Sponsors and their respective affiliates collectively beneficially own a specified amount of the outstanding shares of our Class A and Class B common stock. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board of directors to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2019, 2020 and 2021, respectively. Messrs.                      will be assigned to Class I, Messrs.                      will be assigned to Class II, and Messrs.                      will be assigned to Class III. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Director Independence

The board of directors is in the process of reviewing the independence of our directors using the independence standards of the NYSE. Currently, we anticipate that our board of directors will determine that each of Messrs. Levy, Sult, Holland, Keenan and Stoneburner are independent within the meaning of the NYSE listing standards currently in effect and that Messrs. Sult and                  are independent within the meaning of 10A-3 of the Exchange Act.

Committees of the Board of Directors

Our board of directors currently has an audit committee and will establish a compensation committee and a nomination and governance committee prior to the consummation of this offering. In addition, our board of directors may establish such other committees as it determines necessary or advisable from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

Rules implemented by the NYSE and the SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange

117

Act, subject to transitional relief during the one-year period following the completion of the offering contemplated by this prospectus. Mr. Sult is currently the sole member and chairman of our audit committee and, prior to completion of the offering, we expect to appoint Messrs.              and              as members of our audit committee. Although our board of directors has not made such determination yet, we anticipate that our board of directors will determine that Messrs. Sult and              are independent under the rules of the NYSE and the SEC. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors within one year following the completion of this offering. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experiences, possesses the attributes outlined in such rules. Our board of directors has determined that Mr. Sult satisfies the definition of an “audit committee financial expert.”

This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards, which will be available on our website prior to the completion of this offering. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Compensation Committee

We will establish a compensation committee prior to completion of this offering. We anticipate that the compensation committee will consist of three directors, Messrs.                     , of whom Messrs.                      will be “independent” under the rules of the SEC, the Sarbanes-Oxley Act of 2002 and the NYSE. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. We expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC, the PCAOB and applicable stock exchange or market standards.

Nominating and Corporate Governance Committee

We will establish a nominating and corporate governance committee prior to completion of this offering. We anticipate that the nominating and corporate governance committee will consist of three directors, Messrs.                     , of whom Messrs.                      will be “independent” under the rules of the SEC, the Sarbanes-Oxley Act of 2002 and the NYSE. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors; develop and oversee our internal corporate governance processes; and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities

118

laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

119

EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer, our next two other most highly compensated officers at the end of the last completed fiscal year and up to two additional individuals who would have been considered one of our next two most highly compensated officers except that such individuals did not serve as executive officers at the end of the last completed fiscal year. Accordingly, our named executive officers are:

Name	Principal Position
Ben “Bud” M. Brigham	Executive Chairman
Robert M. Roosa	Chief Executive Officer and Director
Blake C. Williams	Chief Financial Officer

Summary Compensation Table

The following table summarizes, with respect to our named executive officers, information relating to compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2017.

Name and Principal Position	Year		Salary ($)		Bonus ($)(1)		All Other Compensation ($)(2)		Total ($)
Ben “Bud” M. Brigham (Executive Chairman)		2017	$	227,116	$	59,490	$	6,207	$	292,813
Robert M. Roosa (Chief Executive Officer and Director)		2017	$	350,180	$	122,500	$	36,832	$	509,512
Blake C. Williams (Chief Financial Officer)(3)		2017	$	108,381	$	70,000	$	37,511	$	215,892

(1) Amounts in this column reflect discretionary bonuses earned by our named executive officers during fiscal year 2017.

(2) Amounts in this column reflect (a) matching contributions to the 401(k) Plan (as defined below) made on behalf of our named executive officers for 2017 and (b) health and welfare plan premiums paid for the benefit of our named executive officers for 2017. See “—Additional Narrative Disclosures—Other Benefits” below for more information on matching contributions to the 401(k) Plan.

(3) Mr. Williams began serving as our Chief Financial Officer on June 15, 2017. As a result, the amount shown in the “Salary” column for Mr. Williams reflects amounts earned from June 15, 2017 through December 31, 2017.

120

Outstanding Equity Awards at 2017 Fiscal Year-End

The following table reflects information regarding outstanding equity-based awards held by our Named Executive Officers as of December 31, 2017.

	Option Awards (1)
Name	Number of Securities Underlying Unexercised Options (#) Exercisable (2)		Number of Securities Underlying Unexercised Options (#) Unexercisable (2)		Option Exercise Price ($)		Option Expiration Date
Ben “Bud” M. Brigham
Series M-1 Incentive Units		1,200		—		N/A		N/A
Series M-2 Incentive Units		1,200		—		N/A		N/A
Series M-3 Incentive Units		1,200		—		N/A		N/A
Series M-4 Incentive Units		1,200		—		N/A		N/A
Series Z-1 Incentive Units		390		260		N/A		N/A
Series Z-2 Incentive Units		390		260		N/A		N/A
Series Z-3 Incentive Units		390		260		N/A		N/A
Series Z-4 Incentive Units		390		260		N/A		N/A
Robert M. Roosa
Series M-1 Incentive Units		1,000		—		N/A		N/A
Series M-2 Incentive Units		1,000		—		N/A		N/A
Series M-3 Incentive Units		1,000		—		N/A		N/A
Series M-4 Incentive Units		1,000		—		N/A		N/A
Series Z-1 Incentive Units		210		140		N/A		N/A
Series Z-2 Incentive Units		210		140		N/A		N/A
Series Z-3 Incentive Units		210		140		N/A		N/A
Series Z-4 Incentive Units		210		140		N/A		N/A
Blake C. Williams
Series Z-1 Incentive Units		37.5		25		N/A		N/A
Series Z-2 Incentive Units		37.5		25		N/A		N/A
Series Z-3 Incentive Units		37.5		25		N/A		N/A
Series Z-4 Incentive Units		37.5		25		N/A		N/A

(1) This table reflects information regarding incentive units in Brigham Resources (the “Incentive Units”) granted to our named executive officers that were outstanding as of December 31, 2017. The Incentive Units are intended to constitute “profits interests” and represent actual (non-voting) equity interests that have no liquidation value for U.S. federal income tax purposes on the date of grant but are designed to gain value only after the underlying assets have realized a certain level of growth and return to those persons who hold certain other classes of equity. We believe that, despite the fact that the Incentive Units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as “options” for purposes of the SEC’s executive compensation disclosure rules under the definition provided in Item 402(m)(5)(i) of Regulation S-K since these awards have “option-like features.” The Incentive Units are divided into two classes and each class is further divided into four tiers. For more information on the Incentive Units, see “—Additional Narrative Disclosures—Incentive Units” below.

(2) Awards reflected as “Exercisable” are Incentive Units that have vested while awards reflected as “Unexercisable” are Incentive Units that have not yet vested.

121

Additional Narrative Disclosures

Compensation Philosophy

As a general matter, our executive compensation programs are designed to be:

• Performance-Based

○ A significant portion of total compensation will be performance-based.

○ Performance metrics will focus business strategy and corporate objectives on total shareholder return.

○ Awards will be leveraged to achievement of performance goals and the creation of shareholder value.

• Shareholder-Aligned

○ Long-term incentives will be equity-based and will represent a significant portion of the total compensation of executives and other key employees.

○ The design of long-term incentive awards will focus on the creation of shareholder value and encourage retention through the use of multi-year vesting schedules.

• Competitive

○ Our compensation program will be competitive with the market and support the company’s ability to attract and retain key talent.

○ Total compensation will be perceived as fair and equitable, both internally and externally.

• Clear and Well-Communicated

○ Straightforward, transparent compensation programs deliver a strong, clear message.

○ Compensation programs that conform with prevailing market practices and corporate governance standards provide transparency and comfort to shareholders.

○ Appropriately managing risk within the compensation program facilitates the creation of shareholder value.

Following the consummation of this offering, we expect that our named executive officers will receive (i) an annualized base salary, (ii) the grant of equity-based awards (with approximately one-half of such awards subject to time-based vesting conditions and the other one-half of such awards subject to performance-based vesting conditions) and (iii) eligibility to participate in employee benefits on the same basis as our other employees.

Base Salary

Each named executive officer’s base salary is a fixed component of compensation that does not vary depending on the level of performance achieved. Base salaries are determined for each named executive officer based on his position and responsibility. Historically, the board of managers of our predecessor reviewed the base salaries for each named executive officer annually as well as at the time of any promotion or significant change in job responsibilities and, in connection with each review, such board of managers considered individual and company performance over the course of the applicable year.

Effective as of October 1, 2018, the annualized base salary of our named executive officers will be as follows:

Name	Base Salary
Ben “Bud” M. Brigham	$	250,000
Robert M. Roosa	$	500,000
Blake C. Williams	$	350,000

122

Cash Bonuses

We do not maintain a formal bonus program for our named executive officers. However, our named executive officers have historically been eligible to receive discretionary bonuses, based in part upon pre-established performance criteria, to recognize their significant contributions and aid in our retention efforts. Historically, the board of managers of our predecessor has determined whether each named executive officer is eligible to receive a cash bonus for a given year and sets the amount of such cash bonus.

Going forward, our named executive officers are not expected to be eligible to receive an annual cash bonus.

Other Benefits

We offer participation in broad-based retirement, health and welfare plans to all of our employees, including our named executive officers who are eligible to participate in such plans on the same basis as all other employees. We maintain a plan intended to provide benefits under section 401(k) of the Internal Revenue Code of 1986, as amended (the “401(k) Plan”), where employees are allowed to contribute portions of their base compensation into a retirement account in order to encourage all employees, including any participating named executive officers, to save for the future. For the 2017 plan year, we provided an effective matching contribution equal to 100% of the first 6% of an employee’s eligible compensation.

Incentive Units

In 2013 and 2015, each of our named executive officers were granted Incentive Units pursuant to the limited liability company agreement governing Brigham Resources at the time. The Incentive Units are intended to constitute “profits interests” and represent actual (non-voting) equity interests that have no liquidation value for U.S. federal income tax purposes on the date of grant but are designed to gain value only after the underlying assets realize a certain level of growth and return to those persons who hold certain other classes of equity. The Incentive Units are divided into two classes, Series M units and Series Z units. The Series M units granted to our named executive officers in 2013 are fully vested. The Series Z units granted to our named executive officers in 2015 vested as to 20% on the applicable date of grant and an additional 20% on each of the first three anniversaries of such date of grant in 2016, 2017 and 2018, such that the Series Z units granted to our named executive officers in 2015 are 80% vested. The remaining 20% of such Series Z units will vest on the fourth anniversary of the applicable date of grant in 2019, subject to continued employment by us through such vesting date. In addition, in 2018, Mr. Williams was granted additional Incentive Units, specifically 820 Series M-1, M-2, M-3 and M-4 units and 384 Series Z-1, Z-2, Z-3 and Z-4 units. The Series M and Series Z units granted to Mr. Williams in 2018 vested as to 20% on the applicable date of grant and will vest as to an additional 20% on each of the first four anniversaries of such date of grant, subject to continued employment by us through such vesting dates.

In connection with this offering, Brigham Equity Holdings will undergo a reorganization transaction in order to preserve the economic rights and vesting provisions applicable to the Incentive Units. As a result of such transaction, (i) holders of units other than Incentive Units and holders of vested Incentive Units will receive a number of Brigham LLC Units determined based on the value attributable to such units (assuming all unvested Incentive Units are vested) and (ii) holders of unvested Incentive Units will receive a number of Brigham LLC Units determined in the same manner when and if such Incentive Units vest. In addition, the rights of holders of vested Incentive Units and holders of unvested Incentive Units to a pro rata share of any Brigham LLC Units attributable to unvested Incentive Units that are ultimately forfeited prior to vesting will be preserved. This will be accomplished through Brigham Equity Holdings holding the Brigham LLC Units attributable to unvested Incentive Units until such time as such Incentive Units vest, and the holders of both vested and unvested Incentive Units retaining certain rights in Brigham Equity Holdings.

Compensation Following This Offering

In connection with this offering, we intend to grant our named executive officers equity-based awards under the 2018 Plan (as defined under “—2018 Long Term Incentive Plan” below), which will consist of (i) for Messrs.

123

Roosa and Williams, restricted stock units subject to time-based vesting (“RSUs”) and (ii) for Messrs. Brigham, Roosa and Williams, restricted stock units subject to performance-based vesting (“PSUs”). Mr. Brigham will only receive PSUs. For Messrs. Roosa and Williams, approximately one-half of the overall value of their equity-based awards will consist of RSUs while the other one-half of the overall value of their equity-based awards will consist of PSUs.

The RSUs will vest in equal installments on the first three anniversaries of the applicable date of grant, so long as the named executive officer remains continuously employed by us through each vesting date. It is anticipated that Mr. Roosa will receive a number of RSUs that have a fair market value on the applicable date of grant between $900,000 and $1,125,000 while Mr. Williams will receive a number of RSUs that have a fair market value on the applicable date of grant between $400,000 and $500,000, provided that the number of RSUs granted will ultimately depend on the value of our company at the time of grant.

The PSUs will be eligible to be earned based on the total shareholder return (“TSR”) of our company for a three-year performance period, so long as the named executive officer remains continuously employed by us through the end of such performance period (other than Mr. Brigham who must remain continuously employed by us through the end of a two-year service period). Between 0% and 200% of the PSUs are eligible to be earned based on our achieving an absolute TSR on an annualized basis based on the following pre-established annual return goals:

Level of Achievement	Pre-Established Annual Return Goal	Number of PSUs Earned
Threshold	10% annualized return (1.33x)	50%
Target	15% annualized return (1.52x)	100%
Maximum	25% annualized return (1.95x)	200%

In addition, the Administrator (as defined under “—2018 Long Term Incentive Plan” below) will retain discretion to adjust the number of PSUs earned based on our relative TSR as compared to a benchmarking peer group over the three-year performance period. The Administrator may increase the number of PSUs that have been earned by 20% if our TSR is in the top decile of the benchmarking peer group or decrease the number of PSUs that have been earned by 20% if our TSR is in the bottom decile of the benchmarking peer group. It is anticipated that our named executive officers will receive a number of PSUs that have a fair market value on the applicable date of grant, based on target, between (i) $6,000,000 and $7,500,000 for Mr. Brigham, (ii) $900,000 and $1,125,000 for Mr. Roosa and (iii) $400,000 and $500,000 for Mr. Williams, provided that the target number of PSUs granted will ultimately depend on the value of our company at the time of grant.

Once vested or earned, as applicable, the RSUs and PSUs will be settled in shares of our common stock.

2018 Long Term Incentive Plan

In connection with this offering, we intend to adopt an omnibus equity incentive plan, the Brigham Minerals, Inc. 2018 Long Term Incentive Plan (the “2018 Plan”), for the employees, consultants and directors of Brigham Minerals and its affiliates who perform services for us. The following description of the 2018 Plan is based on the form we anticipate adopting, but the 2018 Plan has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final form of the 2018 Plan once adopted.

The 2018 Plan will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“incentive options”); (ii) stock options that do not qualify as incentive stock options (“nonstatutory options” and, together with incentive options, “options”); (iii) stock appreciation rights (“SARs”); (iv) restricted stock awards (“restricted stock awards”); (v) restricted stock units (“restricted stock units” or “RSUs”); (vi) bonus stock (“bonus stock awards”); (vii) dividend equivalents; (viii) other stock-based awards;

124

(ix) cash awards; and (x) substitute awards (referred to collectively herein with the other awards as the “awards”). The vesting, exercise or settlement of awards may be subject to the achievement of one or more performance criteria selected by the Administrator.

Eligibility

Our employees, consultants and non-employee directors, and employees, consultants and non-employee directors of our affiliates, will be eligible to receive awards under the 2018 Plan.

Administration

Our board of directors, or a committee thereof (as applicable, the “Administrator”), will administer the 2018 Plan pursuant to its terms and all applicable state, federal or other rules or laws. The Administrator will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common stock), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting or exercisability of an award, delegate duties under the 2018 Plan and execute all other responsibilities permitted or required under the 2018 Plan.

Securities to be Offered

Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event, a number of shares of our Class A common stock equal to 12% of our Class A common stock (on a fully diluted basis) outstanding upon the completion of this offering will be available for delivery pursuant to awards under the 2018 Plan. If an award under the 2018 Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the 2018 Plan.

Types of Awards

Options. We may grant options to eligible persons including: (i) incentive options (only to our employees or those of our subsidiaries) which comply with Section 422 of the Code; and (ii) nonstatutory options. The exercise price of each option granted under the 2018 Plan will be stated in the option agreement and may vary; however, the exercise price for an option must not be less than the fair market value per share of common stock as of the date of grant (or 110% of the fair market value for certain incentive options), nor may the option be re-priced without the prior approval of our stockholders. Options may be exercised as the Administrator determines, but not later than ten years from the date of grant. The Administrator will determine the methods and form of payment for the exercise price of an option (including, in the discretion of the Administrator, payment in common stock, other awards or other property) and the methods and forms in which common stock will be delivered to a participant.

SARs. A SAR is the right to receive a share of common stock, or an amount equal to the excess of the fair market value of one share of the common stock on the date of exercise over the grant price of the SAR, as determined by the Administrator. The exercise price of a share of common stock subject to the SAR shall be determined by the Administrator, but in no event shall that exercise price be less than the fair market value of the common stock on the date of grant. The Administrator will have the discretion to determine other terms and conditions of an SAR award.

Restricted stock awards. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the Administrator in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the Administrator. Except as otherwise provided under the terms of the 2018 Plan or an award agreement, the holder of a restricted stock award will have rights as a stockholder, including the right to vote the common stock subject to the restricted stock award or to receive dividends on the common stock subject to the restricted stock

125

award during the restriction period. The Administrator shall provide, in the restricted stock award agreement, whether the restricted stock will be forfeited upon certain terminations of employment. Unless otherwise determined by the Administrator, common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, will be subject to restrictions and a risk of forfeiture to the same extent as the restricted stock award with respect to which such common stock or other property has been distributed.

Restricted stock units. RSUs are rights to receive common stock, cash, or a combination of both at the end of a specified period. The Administrator may subject RSUs to restrictions (which may include a risk of forfeiture) to be specified in the RSU award agreement, and those restrictions may lapse at such times determined by the Administrator. Restricted stock units may be settled by delivery of common stock, cash equal to the fair market value of the specified number of shares of common stock covered by the RSUs, or any combination thereof determined by the Administrator at the date of grant or thereafter. Dividend equivalents on the specified number of shares of common stock covered by RSUs may be paid on a current, deferred or contingent basis, as determined by the Administrator on or following the date of grant.

Bonus stock awards. The Administrator will be authorized to grant common stock as a bonus stock award. The Administrator will determine any terms and conditions applicable to grants of common stock, including performance criteria, if any, associated with a bonus stock award.

Dividend Equivalents. Dividend equivalents entitle a participant to receive cash, common stock, other awards or other property equal in value to dividends paid with respect to a specified number of shares of our common stock, or other periodic payments at the discretion of the Administrator. Dividend equivalents may be granted on a free-standing basis or in connection with another award (other than a restricted stock award or a bonus stock award).

Other Stock-Based Awards. Other stock-based awards are awards denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, the value of our common stock.

Cash Awards. Cash awards may be granted on a free-standing basis, as an element of or a supplement to, or in lieu of any other award.

Substitute Awards. Awards may be granted in substitution or exchange for any other award granted under the 2018 Plan or under another equity incentive plan or any other right of an eligible person to receive payment from us. Awards may also be granted under the 2018 Plan in substitution for similar awards held for individuals who become participants as a result of a merger, consolidation or acquisition of another entity by or with the Company or one of our affiliates.

Certain Transactions

If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of common stock, appropriate adjustments will be made by the Administrator in the shares subject to an award under the 2018 Plan. The Administrator will also have the discretion to make certain adjustments to awards in the event of a change in control, such as accelerating the vesting or exercisability of awards, requiring the surrender of an award, with or without consideration, or making any other adjustment or modification to the award that the Administrator determines is appropriate in light of such transaction.

Plan Amendment and Termination

Our board of directors may amend or terminate the 2018 Plan at any time; however, stockholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing

126

standards. The Administrator will not have the authority, without the approval of stockholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The 2018 Plan will remain in effect for a period of ten years (unless earlier terminated by our board of directors).

Clawback

All awards under the 2018 Plan will be subject to any clawback or recapture policy adopted by the Company, as in effect from time to time.

Director Compensation

Brigham Minerals, the issuer of Class A common stock in this offering, was formed in June 2018. No obligations with respect to compensation for directors have been accrued or paid for any periods following such formation date. Individuals serving on the board of managers of our predecessor did not receive any compensation for their services on such board during fiscal year 2017.

Going forward, we believe that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. We also believe that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interest of directors with our stockholders.

We are currently reviewing the non-employee director compensation packages provided by certain peer companies and intend to implement a non-employee director compensation program in connection with this offering.

Directors who are also our employees will not receive any additional compensation for their service on our board of directors.

127

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our Class A common stock and Class B common stock that, upon the consummation of our corporate reorganization and this offering, will be owned by:

• each person known to us to beneficially own more than 5% of any class of our outstanding shares of Class A common stock;

• each of our directors;

• our Named Executive Officers; and

• all of our directors and executive officers as a group.

All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors or Named Executive Officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Brigham Minerals, Inc., 5914 W. Courtyard Dr., Suite 100, Austin, Texas 78730.

Shares Beneficially Owned Before this Offering

Shares Beneficially Owned After this Offering (Assuming No Exercise of the Underwriters’  Option to Purchase Additional Shares)(2)

Name of Beneficial Owner(1)

Class A Common Stock

Class B Common Stock

Combined Voting Power(3)

Number

%

Number

%

Number

%

Number

%

5% Shareholders:

Warburg Pincus & Company US, LLC(4)

%

%

%

%

Yorktown Partners LLC(5)

%

%

%

%

PBRA, LLC(6)

%

%

%

%

Directors and Named Executive Officers:

Ben “Bud” M. Brigham

%

%

%

%

Robert M. Roosa

%

%

%

%

Blake C. Williams

%

%

%

%

Harold D. Carter

%

%

%

%

John A. Holland(7)

%

%

%

%

W. Howard Keenan, Jr.(8)

%

%

%

%

James R. Levy(7)

%

%

%

%

Richard Stoneburner(9)

%

%

%

%

John R. Sult

%

%

%

%

Directors and Executive Officers as a Group (                     Persons)

%

%

%

%

(1) The amounts and percentages of Class A common stock and Class B common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of Class A common stock and Class B common stock, except to the extent this power may be shared with a spouse.

128

(2) Subject to the terms of the Brigham LLC Agreement, the Existing Owners, subject to certain limitations, will have the right to require Brigham LLC to redeem all or a portion of their Brigham LLC Units for shares of Class A common stock at a redemption ratio of one share of Class A common stock for each Brigham LLC Unit redeemed. See “Certain Relationships and Related Person Transactions—Brigham LLC Agreement.” Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days. The Company has the option to deliver cash in lieu of shares of Class A common stock upon exercise by an Existing Owner of the Redemption Right. As a result, beneficial ownership of Class B common stock and Brigham LLC Units is not reflected as beneficial ownership of shares of our Class A common stock for which such units and stock may be redeemed.

(3) Represents percentage of voting power of our Class A common stock and Class B common stock voting together as a single class. The Existing Owners will hold one share of Class B common stock for each Brigham LLC Unit that they own. Each share of Class B common stock has no economic rights, but entitles the holder thereof to one vote for each Brigham LLC Unit held by such holder. Accordingly, the Existing Owners collectively have a number of votes in Brigham Minerals equal to the number of Brigham LLC Units that they hold. The number of shares of Class A common stock, Class B common stock and Brigham LLC Units to be issued to the Existing Owners is based on the implied equity value of Brigham LLC immediately prior to this offering, based on an initial public offering price of $            per share of Class A common stock, the midpoint of the price range set forth on the cover page of this prospectus. Any increase or decrease of the assumed initial public offering price will result in an increase or decrease in the number of shares of Class A common stock received by the holders of Incentive Units in Brigham LLC, but will not affect the aggregate numbers of shares of Class A common stock held by the Existing Owners. At an assumed public offering price of $             (the midpoint of the range set forth on the cover of this prospectus), Incentive Unit holders will receive             million shares of Class A common stock. A $1.00 increase in the assumed public offering price would increase the aggregate number of shares to be received by the Incentive Unit holders by             million shares. A $1.00 decrease in the assumed public offering price would decrease the aggregate number of shares to be received by the Incentive Unit holders by            million shares. See “Corporation Reorganization,” “Description of Capital Stock—Class A Common Stock” and “Description of Capital Stock—Class B Common Stock.”

(4) Includes shares that will be collectively owned by certain affiliates of Warburg Pincus & Company US, LLC (“Warburg Pincus US”), including: (1) Warburg Pincus Private Equity (E&P) XI-A (Brigham), LLC, a Delaware limited liability company (“WPPE E&P XI-A Brigham”), (2) Warburg Pincus XI (E&P) Partners-A (Brigham), LLC, a Delaware limited liability company (“WP XI E&P Partners-A Brigham”), (3) Warburg Pincus Private Equity (E&P) XI (Brigham), LLC, a Delaware limited liability company (“WPPE E&P XI Brigham”), (4) Warburg Pincus XI (E&P) Partners-B (Brigham), LLC, a Delaware limited liability company (“WP XI E&P Partners-B Brigham”), (5) WP Brigham Holdings, L.P., a Delaware limited partnership (“WP Brigham Holdings”), (6) Warburg Pincus Energy (E&P)-A (Brigham), LLC, a Delaware limited liability company (“WPE E&P-A Brigham”), (7) Warburg Pincus Energy (E&P) Partners-A (Brigham), LLC, a Delaware limited liability company (“WPE E&P Partners-A Brigham”), (8) Warburg Pincus Energy (E&P) (Brigham), LLC, a Delaware limited liability company (“WPE E&P Brigham”), (9) Warburg Pincus Energy (E&P) Partners-B (Brigham), LLC, a Delaware limited liability company (“WPE E&P Partners-B Brigham”), (10) WP Energy Partners (E&P) (Brigham), LLC, a Delaware limited liability company (“WPE Partners E&P Brigham”), (11) WP Energy Brigham Holdings, L.P., a Delaware limited partnership (“WPE Brigham Holdings”), and (12) WP Energy Partners Brigham Holdings, L.P., a Delaware limited partnership (“WPE Partners Brigham Holdings,” and together with the entities in (1) through (11), the “WP Group”).

Warburg Pincus Private Equity (E&P) XI-A, L.P., a Delaware limited partnership (“WPPE E&P XI-A”), is the sole member of WPPE E&P XI-A Brigham. Warburg Pincus XI (E&P) Partners – A, L.P., a Delaware limited partnership (“WP XI E&P Partners-A”), is the sole member of WP XI E&P Partners-A Brigham. Warburg Pincus Energy (E&P)-A, L.P., a Delaware limited partnership (“WPE E&P-A”), is the sole and

129

managing member of WPE E&P-A Brigham. Warburg Pincus Energy (E&P) Partners-A, L.P., a Delaware limited partnership (“WPE E&P Partners-A”), is the sole and managing member of WPE E&P Partners-A Brigham. Effective as of July 16, 2018, Brigham Minerals is the sole and managing member of WPPE E&P XI Brigham, WP XI E&P Partners-B Brigham, WPE E&P Brigham, WPE E&P Partners-B Brigham and WPE Partners E&P Brigham. Brigham Parent Holdings, L.P., a Delaware limited partnership (“Brigham Parent Holding”) is the sole shareholder of Brigham Minerals.

Warburg Pincus (E&P) XI, L.P., a Delaware limited partnership (“WP XI E&P GP”), is the (i) general partner of each of WP Brigham Holdings, WPPE E&P XI-A, WP XI E&P Partners-A and Brigham Parent Holdings. Warburg Pincus (E&P) XI LLC, a Delaware limited liability company (“WP XI E&P LLC”), is the general partner of WP XI E&P GP. Warburg Pincus Partners (E&P) XI LLC, a Delaware limited liability company (“WP Partners E&P XI LLC”), is the sole member of WP XI E&P LLC. Warburg Pincus Partners II (US), L.P., a Delaware limited partnership (“WPP II US”), is the managing member of WP Partners E&P XI LLC. Warburg Pincus US is the general partner of WPP II US.

Warburg Pincus (E&P) Energy GP, L.P., a Delaware limited partnership (“WPE E&P GP”), is the general partner of each of WPE Brigham Holdings, WPE Partners Brigham Holdings, WPE E&P-A and WPE E&P Partners-A. Warburg Pincus (E&P) Energy LLC, a Delaware limited liability company (“WPE E&P LLC,” and together with WP XI E&P GP, WP XI E&P LLC, WP Partners E&P XI LLC, WPE E&P GP, WPP II US and Warburg Pincus US, the “Warburg Pincus GP Entities”), is the general partner of WPE E&P GP. WPP II US is the managing member of WPE E&P LLC. As noted above, Warburg Pincus US is the general partner of WPP II US. Warburg Pincus is the manager of each of WP Brigham Holdings, WPPE E&P XI-A, WP XI E&P Partners-A, WPE Brigham Holdings, WPE Partners Brigham Holdings, WPE E&P-A and WPE E&P Partners-A. Charles R. Kaye and Joseph P. Landy are the Managing Members of Warburg Pincus US and the Managing Members and Co-Chief Executive Officers of Warburg Pincus and, as such, may be deemed to control each of the foregoing entities. Messrs. Kaye and Landy disclaim beneficial ownership of all shares held by such entities.

(5) Includes shares owned by Yorktown Energy Partners IX, L.P. (“Yorktown IX”), shares owned by Yorktown Energy Partners X, L.P. (“Yorktown X”) and shares owned by YT Brigham Co Investment Partners, LP (“YT Brigham” and together with Yorktown IX and Yorktown X, each, a “Yorktown Fund”).

Yorktown IX Company LP is the sole general partner of Yorktown IX. Yorktown IX Associates LLC is the sole general partner of Yorktown IX Company LP. As a result, Yorktown IX Associates LLC may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the common stock owned by Yorktown IX. Yorktown IX Company LP and Yorktown IX Associates LLC disclaim beneficial ownership of the common stock held by Yorktown IX in excess of their pecuniary interest therein. W. Howard Keenan, Jr. is a manager of Yorktown IX Associates LLC. Mr. Keenan disclaims beneficial ownership of the common stock held by Yorktown IX. None of Yorktown IX Associates LLC, Yorktown IX Company LP or Yorktown IX beneficially owns any of the common stock held by any other

Yorktown Fund. Yorktown X Company LP is the sole general partner of Yorktown X.

Yorktown X Associates LLC is the sole general partner of Yorktown X Company LP. As a result, Yorktown X Associates LLC may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the common stock owned by Yorktown X. Yorktown X Company LP and Yorktown X Associates LLC disclaim beneficial ownership of the common stock held by Yorktown X in excess of their pecuniary interest therein. W. Howard Keenan, Jr. is a manager of Yorktown X Associates LLC. Mr. Keenan disclaims beneficial ownership of the common stock held by Yorktown X. None of Yorktown X Associates LLC, Yorktown X Company LP or Yorktown X beneficially owns any of the common stock held by any other Yorktown Fund.

YT Brigham Company LP is the sole general partner of YT Brigham. YT Brigham Associates LLC is the sole general partner of YT Brigham Company LP. As a result, YT Brigham Associates LLC may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the common stock owned by YT Brigham. YT Brigham Company LP and YT Brigham Associates LLC disclaim beneficial

130

ownership of the common stock held by YT Brigham in excess of their pecuniary interest therein. W. Howard Keenan, Jr. is a manager of YT Brigham Associates LLC. Mr. Keenan disclaims beneficial ownership of the common stock held by YT Brigham. None of YT Brigham Company LP, YT Brigham Associates LLC or YT Brigham beneficially owns any of the common stock held by any other Yorktown Fund.

(6) Consists of shares of common stock held indirectly by Pine Brook Capital Partners II, L.P. (“Pine Brook Fund II”). Pine Brook Road Associates II, L.P. is the general partner of Pine Brook Fund II. Pine Brook Road Advisors, L.P., acting through an affiliate, serves as investment manager to Pine Brook Fund II. PBRA, LLC controls both Pine Brook Road Associates II, L.P. and Pine Brook Road Advisors, L.P. Howard Newman is the sole member of PBRA, LLC and has investment and voting control over the shares held or controlled by Pine Brook Fund II. The address of each of the entities identified in this note is c/o Pine Brook Road Partners, LLC, 60 East 42nd Street, 50th Floor, New York, NY 10165. Howard Newman, PBRA, LLC, Pine Brook Road Associates II, L.P. and Pine Brook Road Advisors, L.P. each disclaims beneficial ownership of the securities reported herein, except to the extent of its pecuniary interest therein, if any.

(7) All shares of common stock indicated as indirectly owned by the Reporting Person are included because of his affiliation with Warburg Pincus, due to which the Reporting Person may be deemed to have an indirect pecuniary interest (within the meaning of Rule 16a-1 under the Exchange Act) in an indeterminate portion of the shares of common stock owned by Warburg Pincus and its affiliated entities. The Reporting Person disclaims beneficial ownership of all shares of common stock attributable to Warburg Pincus and its affiliated entities except to the extent of his direct pecuniary interest therein. See “Management—Directors and Executive Officers” for a description of the Reporting Person’s affiliation with Warburg Pincus.

(8) All shares of common stock indicated as indirectly owned by the Reporting Person are included because of his affiliation with Yorktown, due to which the Reporting Person may be deemed to have an indirect pecuniary interest (within the meaning of Rule 16a-1 under the Exchange Act) in an indeterminate portion of the shares of common stock owned by Yorktown and its affiliated entities. The Reporting Person disclaims beneficial ownership of all shares of common stock attributable to Yorktown and its affiliated entities except to the extent of his direct pecuniary interest therein. See “Management—Directors and Executive Officers” for a description of the Reporting Person’s affiliation with Yorktown.

(9) All shares of common stock indicated as indirectly owned by the Reporting Person are included because of his affiliation with Pine Brook, due to which the Reporting Person may be deemed to have an indirect pecuniary interest (within the meaning of Rule 16a-1 under the Exchange Act) in an indeterminate portion of the shares of common stock owned by Pine Brook and its affiliated entities. The Reporting Person disclaims beneficial ownership of all shares of common stock attributable to Pine Brook and its affiliated entities except to the extent of his direct pecuniary interest therein. See “Management—Directors and Executive Officers” for a description of the Reporting Person’s affiliation with Pine Brook.

131

CORPORATE REORGANIZATION

Corporate Restructuring

Brigham Minerals was incorporated as a Delaware corporation in June 2018 by an affiliate of Warburg Pincus. Brigham Minerals and certain entities affiliated with Warburg Pincus, Yorktown and Pine Brook, our management and our other Existing Owners currently, directly or indirectly through Brigham Minerals, own all of the membership interests in Brigham LLC, which in turn indirectly owns all of the outstanding membership interests in the Minerals Subsidiaries.

Brigham Minerals acquired an indirect interest in Brigham Resources on July 16, 2018, in a series of restructuring transactions that are collectively referred to in this prospectus as the July 2018 restructuring. In the July 2018 restructuring, certain entities affiliated with Warburg Pincus contributed all of their respective interests in certain wholly owned “blocker” 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 contribution agreement effecting the July 2018 restructuring is filed as an exhibit to the registration statement of which this prospectus forms a part. As a result of the July 2018 restructuring, Brigham Minerals became wholly owned by certain entities affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a membership interest in Brigham Resources. The other Existing Owners held all of the remaining outstanding membership interests of Brigham Resources.

Prior to the offering, Brigham Resources will undergo a second series of restructuring transactions that are collectively referred to in this prospectus as the October 2018 restructuring. In the October 2018 restructuring, Brigham Resources will become a wholly owned subsidiary of Brigham LLC, which will be a wholly owned subsidiary of Brigham Equity Holdings, and Brigham Equity Holdings will be wholly owned by the Existing Owners, directly or indirectly through Brigham Minerals. As a result of the foregoing transactions, there will be no change in the control or economic interests of the Existing Owners in Brigham Resources, although their ownership will be indirect through Brigham Equity Holdings and its wholly owned subsidiary Brigham LLC.

Following this offering and the reorganization transactions described below, Brigham Minerals will be a holding company whose sole material asset will consist of direct and indirect membership interests of Brigham LLC, which will wholly own Brigham Resources. Brigham Resources will continue to wholly own the Minerals Subsidiaries, which own all of our operating assets. After the consummation of the transactions contemplated by this prospectus, Brigham Minerals will be the sole managing member of Brigham LLC and will be responsible for all operational, management and administrative decisions relating to Brigham LLC’s business.

Prior to our corporate reorganization, all of the interests in Brigham Operating will be distributed, directly or indirectly, to the Existing Owners. As a result, neither Brigham Minerals nor Brigham LLC will own any direct or indirect interest in Brigham Operating at the time of the offering.

In connection with this offering,

• Brigham Equity Holdings will distribute all of its equity interests in Brigham LLC, other than its interests in Brigham LLC attributable to certain unvested incentive units in Brigham Equity Holdings, to the Existing Owners (which will result in the ownership in Brigham LLC of our Existing Owners with respect to unvested incentive units remaining consolidated in Brigham Equity Holdings);

• all of the outstanding membership interests in Brigham LLC held by the Existing Owners will be converted into a single class of common units in Brigham LLC, which we refer to in this prospectus as Brigham LLC Units;

• Brigham Minerals will issue              shares of Class A common stock to purchasers in this offering in exchange for the proceeds of this offering;

132

• Following the restructuring, each Brigham Unit Holder, other than Brigham Minerals and its subsidiaries, will receive a number of shares of Class B common stock equal to the number of Brigham LLC Units held by such Brigham Unit Holder following this offering; and

• Brigham Minerals will contribute the net proceeds of this offering to Brigham LLC in exchange for an additional number of Brigham LLC Units such that Brigham Minerals holds a total number of Brigham LLC Units equal to the number of shares of Class A common stock outstanding following this offering.

After giving effect to these transactions and this offering and assuming the underwriters’ option to purchase additional shares is not exercised:

• the Existing Owners will own all of our Class B common stock, representing     % of our capital stock;

• the Existing Owners will own              shares, or     %, of our Class A common stock, representing     % of our capital stock;

• investors in this offering will own              shares, or      %, of our Class A common stock, representing     % of our capital stock;

• Brigham Minerals will own an approximate     % interest in Brigham LLC; and

• the Existing Owners will own an approximate     % interest in Brigham LLC.

If the underwriters’ option to purchase additional shares is exercised in full:

• the Existing Owners will own all of our Class B common stock, representing     % of our capital stock;

• the Existing Owners will own              shares, or     %, of our Class A common stock, representing     % of our capital stock;

• investors in this offering will own             shares, or     %, of our Class A common stock, representing     % of our capital stock;

• Brigham Minerals will own an approximate     % interest in Brigham LLC; and

• the Existing Owners will own an approximate     % interest in Brigham LLC.

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by our stockholders, generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

Following this offering, under the Brigham LLC Agreement, each Brigham Unit Holder will, subject to certain limitations, have a 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. 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

133

of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Brigham LLC Agreement.” The Existing Owners will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

(1) See “—Existing Owners’ Ownership” for a discussion of the interests held by the Existing Owners.

134

Existing Owners’ Ownership

The table below sets forth the percentage ownership of the Existing Owners prior to this offering and after the consummation of this offering.

	Percentage Ownership in Brigham Minerals Prior to this Offering	Percentage Ownership in Brigham LLC Prior to this Offering(2)			Equity Interests Following this Offering
Existing Owners(1)					Brigham LLC Units	Class A Common Stock	Class B Common Stock	Combined Voting Power (%)
Warburg Pincus				%					%
Yorktown				%					%
Pine Brook				%					%
Other executive officers				%					%
Other employees				%					%
Other investors				%					%
			100.0	%					%

(1) The number of shares of Class A common stock, Class B common stock and Brigham LLC Units to be issued to the Existing Owners is based on the implied equity value of Brigham LLC immediately prior to this offering, based on the initial public offering price of $             per share of Class A common stock (which is the midpoint of the range set forth on the cover of this prospectus). At the initial public offering price of $             , Incentive Unit holders will receive approximately            million shares of Class A common stock.

(2) Includes Brigham LLC Units received with respect to the conversion of vested Incentive Units.

Offering

Only Class A common stock will be sold to investors in this offering. Immediately following this offering, there will be              shares of Class A common stock issued and outstanding and              shares of Class A common stock reserved for redemptions of Brigham LLC Units and shares of Class B common stock pursuant to the Brigham LLC Agreement. We estimate that our net proceeds from this offering, after deducting estimated underwriting discounts and commissions and other offering related expenses, will be approximately $             million. We intend to contribute all of the net proceeds from this offering to Brigham LLC in exchange for Brigham LLC Units. Brigham LLC will use the net proceeds to partially repay the outstanding indebtedness under our term loan facility and the remaining net proceeds to fund our future mineral and royalty acquisitions.

As a result of our corporate reorganization and the offering described above (and prior to any redemptions of Brigham LLC Units):

• the investors in this offering will collectively own              shares of Class A common stock (or              shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares);

• the Existing Owners will hold              shares of Class A common stock;

• Brigham Minerals will hold             Brigham LLC Units;

• the Existing Owners will hold                  shares of Class B common stock and a corresponding number of Brigham LLC Units;

• assuming no exercise of the underwriters’ option to purchase additional shares, the investors in this offering will collectively hold     % of the voting power in us (or     % if the underwriters exercise in full their option to purchase additional shares); and

135

• assuming no exercise of the underwriters’ option to purchase additional shares, the Existing Owners will hold     % of the voting power in us (or     % if the underwriters exercise in full their option to purchase additional shares).

Holding Company Structure

Our post-offering organizational structure will allow certain Existing Owners to retain their equity ownership in Brigham LLC, a partnership for U.S. federal income tax purposes. Investors in this offering and other Existing Owners will, by contrast, hold their equity ownership in the form of shares of Class A common stock in Brigham Minerals, and Brigham Minerals is classified as a domestic corporation for U.S. federal income tax purposes. The Existing Owners and Brigham Minerals will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Brigham LLC.

In addition, pursuant to Brigham Minerals’ certificate of incorporation and the Brigham LLC Agreement, Brigham Minerals’ capital structure and the capital structure of Brigham LLC will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one redemption ratio between the Brigham LLC Units and Brigham Minerals’ Class A common stock, among other things.

The holders of Brigham LLC Units, including Brigham Minerals, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Brigham LLC and will be allocated their proportionate share of any taxable loss of Brigham LLC. The Brigham LLC Agreement will provide, to the extent cash is available, for distributions pro rata to the holders of Brigham LLC Units in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities.

136

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Sponsor Contributions

For the three years ended June 30, 2018, we drew a total of approximately $208 million in capital contributions from our Sponsors to fund our operations. After our corporate reorganization, the Sponsors will have no further capital commitments.

Other Transactions with Affiliates

Brigham Land Management (“BLM”) provides the Company with land brokerage services. The services are provided at market prices and are periodically verified by third party quotes. BLM is owned by Vince Brigham, an advisor to the Company and brother of Ben M. Brigham, founder of the Company and Executive Chairman of the Board. For the years ended December 31, 2017 and 2016, the Company paid BLM $0.6 million and $0.7 million, respectively, for land brokerage services. For the six months ended June 30, 2018, the amounts paid to BLM for land brokerage services were immaterial. At June 30, 2018 and December 31, 2017 and 2016, the liabilities recorded for services performed by BLM during the respective periods were immaterial.

Brigham Exploration Company (“BEXP”), owned by Ben M. Brigham, leases some of the Company’s acreage at market rates. For the year ended December 31, 2017, BEXP paid Brigham $0.6 million. There were no payments for the year ended December 31, 2016. For the six months ended June 30, 2018, the amounts paid by BEXP were immaterial.

Brigham LLC Agreement

The Brigham LLC Agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, and the following description of the Brigham LLC Agreement is qualified in its entirety by reference thereto.

In accordance with the terms of the Brigham LLC Agreement, pursuant to the Redemption Right, the Brigham Unit Holders will generally have the right to require Brigham LLC to redeem their 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 reclassifications and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Brigham Minerals (instead of Brigham LLC) will have the right under its Call Right to, for administrative convenience, acquire the tendered Brigham LLC Units directly from the tending Brigham Unit Holder by paying, at its option, either (i) the number of shares of Class A common stock such Existing Owner would have received in the proposed redemption or (ii) an equivalent amount of cash. The Brigham Unit Holders will be permitted to redeem their Brigham LLC Units for shares of our Class A common stock on a quarterly basis, subject to certain de minimis allowances. In addition, any redemptions involving                  or more Brigham LLC Units (subject to the discretion of Brigham Minerals to permit redemptions of a lower number of units) may occur at any time. As the Brigham Unit Holders redeem their Brigham LLC Units, our membership interest in Brigham LLC will be correspondingly increased, the number of shares of Class A common stock outstanding will be increased, and the number of shares of Class B common stock outstanding will be reduced.

Under the Brigham LLC Agreement, subject to the obligation of Brigham LLC to make tax distributions and to reimburse Brigham Minerals for its corporate and other overhead expenses, Brigham Minerals will have the right to determine when distributions will be made to the holders of Brigham LLC Units and the amount of any such distributions. Following this offering, if Brigham Minerals authorizes a distribution, such distribution will be made to the holders of Brigham LLC Units on a pro rata basis in accordance with their respective percentage ownership of Brigham LLC Units.

137

The holders of Brigham LLC Units, including Brigham Minerals, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Brigham LLC and will be allocated their proportionate share of any taxable loss of Brigham LLC. Net profits and net losses of Brigham LLC generally will be allocated to holders of Brigham LLC Units on a pro rata basis in accordance with their respective percentage ownership of Brigham LLC Units, except that certain non-pro rata adjustments will be required to be made to reflect built-in gains and losses and tax depletion, depreciation and amortization with respect to such built-in gains and losses. The Brigham LLC Agreement will provide, to the extent cash is available, for pro rata distributions to the holders of Brigham LLC Units in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities.

The Brigham LLC Agreement will provide that, except as otherwise determined by us or in connection with the exercise of Brigham Minerals’ Call Right, at any time Brigham Minerals issues a share of its Class A common stock or any other equity security, the net proceeds received by Brigham Minerals with respect to such issuance, if any, shall be concurrently invested in Brigham LLC, and Brigham LLC shall issue to Brigham Minerals one Brigham LLC Unit or other economically equivalent equity interest. Conversely, if at any time any shares of Brigham Minerals’ Class A common stock are redeemed, repurchased or otherwise acquired, Brigham LLC shall redeem, repurchase or otherwise acquire an equal number of Brigham LLC Units held by Brigham Minerals, upon the same terms and for the same price, as the shares of our Class A common stock are redeemed, repurchased or otherwise acquired.

Under the Brigham LLC Agreement, the members have agreed that the Existing Owners and/or one or more of their affiliates will be permitted to engage in business activities or invest in or acquire businesses that may compete with our business or do business with any client of ours.

Brigham LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Brigham LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (i) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Brigham LLC, (ii) second, to establish cash reserves for contingent or unforeseen liabilities and (iii) third, to the members in proportion to the number of Brigham LLC Units owned by each of them.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with the Existing Owners. We expect that the agreement will contain provisions by which we agree to register under the federal securities laws the sale of shares of our Class A common stock by the Existing Owners or certain of their affiliates. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective.

Stockholders’ Agreement

In connection with this offering, we will enter into a stockholders’ agreement with the Sponsors. The stockholders’ agreement is expected to provide each of the Sponsors with the right to designate a certain number of nominees to our board of directors, and to designate certain of their nominees as members of each of the committees of our board of directors, so long as such Sponsor and its respective affiliates collectively beneficially own a specified amount of the outstanding shares of our Class A and Class B common stock. In addition, for so long as the Sponsors and their respective affiliates collectively beneficially own a specified amount of the outstanding shares of our Class A and Class B common stock, we will agree not to take certain fundamental actions without the approval of the Sponsors holding a majority of the shares of Class A and Class B common stock collectively beneficially owned by all of the Sponsors and their respective affiliates.

138

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, our board of directors will adopt a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our outstanding shares of Class A common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our outstanding shares of Class A common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our outstanding shares of Class A common stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

139

DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Brigham Minerals will consist of             shares of Class A common stock, $0.01 par value per share, of which             shares will be issued and outstanding, of             shares of Class B common stock, $0.01 par value per share, of which             shares will be issued and outstanding, and             shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Brigham Minerals does not purport to be complete and is qualified in its entirety by reference to the provisions of our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Class A Common Stock

Voting Rights. Except as provided by law or in a preferred stock designation, holders of our Class A common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of Class A common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL.

Dividend Rights. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of Class A common stock are entitled to receive ratably in proportion to the shares of Class A common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments.

Liquidation Rights. Upon our 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 and the liquidation preference of any of our outstanding shares of preferred stock.

Other Matters. The shares of Class A common stock have no preemptive or conversion rights and are not subject to further calls or assessment by us. There are no redemption or sinking fund provisions applicable to our Class A common stock. In connection with this offering, our legal counsel will opine that, subject to the qualifications and limitations stated in such opinion, the shares of our Class A common stock to be issued pursuant to this offering will be fully paid and non-assessable. A copy of such opinion of our legal counsel, including a discussion of the qualifications and limitations thereto, is included as Exhibit 5.1 to the registration statement of which this prospectus forms a part.

Class B Common Stock

Generally. In connection with the reorganization and this offering, each Existing Owner will receive one share of Class B common stock for each Brigham LLC Unit that it holds. Shares of Class B common stock will not be transferrable except in connection with a permitted transfer of a corresponding number of Brigham LLC Units. Accordingly, each Existing Owner will have a number of votes in Brigham Minerals equal to the aggregate number of Brigham LLC Units that it holds.

Voting Rights. Holders of shares of our Class B common stock are entitled to one vote per share held of record on all matters to be voted upon by the stockholders. Holders of shares of our Class A common stock and

140

Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except with respect to the amendment of certain provisions of our certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B common stock so as to affect them adversely, which amendments must be approved by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Dividend Rights. Holders of our Class B common stock do not have any right to receive dividends, unless the dividend consists of shares of our Class B common stock or of rights, options, warrants or other securities convertible or exercisable into or redeemable for shares of Class B common stock paid proportionally with respect to each outstanding share of our Class B common stock and a dividend consisting of shares of Class A common stock or of rights, options, warrants or other securities convertible or exercisable into or redeemable for shares of Class A common stock on the same terms is simultaneously paid to the holders of Class A common stock.

Liquidation Rights. Holders of our Class B common stock do not have any right to receive a distribution upon a liquidation or winding up of Brigham Minerals.

Preferred Stock

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of            shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

We will elect not to be subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for

141

trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

• the transaction is approved by the board of directors before the date the interested stockholder attained that status;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

• on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Our Amended and Restated Certificate of Incorporation and Our Amended and Restated Bylaws

Certain provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Some of these provisions will not apply until our Sponsors and their respective affiliates no longer collectively beneficially own (or otherwise have the right to vote or direct the vote of) more than 50% of our outstanding shares of common stock (the Trigger Event), as described below. Therefore, these provisions could adversely affect the price of our Class A common stock.

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

• provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

• provide that the authorized number of directors constituting our board of directors may be changed only by resolution of the board of directors;

• provide that, after the Trigger Event, all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of our preferred stock, be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares);

• provide that our bylaws can be amended by the board of directors;

• provide that, after the Trigger Event, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any

142

series of our preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

• provide that, after the Trigger Event, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of not less than 66 2/3% of our then outstanding shares of common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding shares of common stock);

• provide that, after the Trigger Event, special meetings of our stockholders may only be called by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote (prior to such time, a special meeting may also be called at the request of our stockholders holding a majority of the then outstanding shares entitled to vote generally in the election of directors voting together as a single class);

• provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us because it generally makes it more difficult for stockholders to replace a majority of the directors;

• provide that the affirmative vote of the holders of not less than 66 2/3% in voting power of all then outstanding shares of common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office, and such removal may only be for “cause”; and

• prohibit cumulative voting on all matters.

Corporate Opportunity

Under our amended and restated certificate of incorporation, to the extent permitted by law:

• our Sponsors and their affiliates have the right to, and have no duty to abstain from, exercising such right to, conduct business with any business that is competitive or in the same line of business as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us;

• if our Sponsors or their affiliates acquire knowledge of a potential transaction that could be a corporate opportunity, they have no duty to offer such corporate opportunity to us; and

• we have renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities.

Forum Selection

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

• any derivative action or proceeding brought on our behalf;

• any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

• any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or

143

• any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. In addition, the enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

• for any breach of their duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

• for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

• for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Registration Rights

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

144

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is             .

Listing

We have applied to list our Class A common stock on the NYSE under the symbol “MNRL.”

145

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for shares of our Class A common stock. Future sales of shares of our Class A common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our Class A common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our Class A common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our Class A common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of              shares of Class A common stock. Of these shares, all of the             shares of Class A common stock (or              shares of Class A common stock if the underwriters’ option to purchase additional shares is exercised) to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of Class A common stock held by existing stockholders will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

In addition, subject to certain limitations and exceptions, pursuant to the terms of the Brigham LLC Agreement, the Existing Owners will each have the right to redeem all or a portion of their Brigham LLC Units for 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 reclassifications, or, at our election, an equivalent amount of cash. Upon consummation of this offering, the Existing Owners will hold Brigham LLC Units, all of which will be redeemable for shares of our Class A common stock. See “Certain Relationships and Related Party Transactions—Brigham LLC Agreement.” The shares of Class A common stock we issue upon such redemptions would be “restricted securities” as defined in Rule 144 described below. However, upon the closing of this offering, we intend to enter into a registration rights agreement with the Existing Owners that will require us to register under the Securities Act these shares of Class A common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our Class A common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

• no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

• shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus when permitted under Rule 144 or Rule 701; and

• shares will be eligible for sale, upon exercise of vested options, upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus.

Lock-up Agreements

We, all of our directors and executive officers and certain of our stockholders and employees have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date

146

of this prospectus, we and they will not, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. See “Underwriting” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person (who has been unaffiliated for at least the past three months) who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our Class A common stock or the average weekly trading volume of shares of our Class A common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchase or otherwise receive shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering are entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under our long-term incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement may be made available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

147

CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the acquisition and holding of shares of common stock by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA), non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be subject to provisions under any other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this registration statement. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions, regulations, rulings or pronouncements will not significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in shares of common stock with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of shares of common stock is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether, in making the investment, the ERISA Plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment is permitted under the terms of the applicable documents governing the Plan;

• whether the acquisition or holding of the shares of common stock will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (please see discussion under “—Prohibited Transaction Issues” below); and

• whether the Plan will be considered to hold, as plan assets, (i) only shares of common stock or (ii) an undivided interest in our underlying assets (please see the discussion under “—Plan Asset Issues” below).

148

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code. The acquisition and/or holding of shares of common stock by an ERISA Plan with respect to which the issuer, the initial purchaser or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, shares of common stock should not be acquired or held by any person investing “plan assets” of any Plan unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or a similar violation of any applicable Similar Laws.

Plan Asset Issues

Additionally, a fiduciary of a Plan should consider whether the Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that we would become a fiduciary of the Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by ERISA Plans are “publicly-offered securities” (as defined in the DOL regulations)—i.e., the equity interests are part of a class of securities that is widely held by 100 or more investors independent of the issuer and each other, are freely transferable, and are either registered under certain provisions of the federal securities laws or sold to the ERISA Plan as part of a public offering under certain conditions;

(b) the entity is an “operating company” (as defined in the DOL regulations)—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors” (as defined in the DOL regulations)—i.e., immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to such assets, and any affiliates thereof) is held by ERISA Plans, IRAs and certain other Plans (but not including governmental plans, foreign plans and certain church plans), and entities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the complexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering acquiring and/or holding shares of our common stock on behalf of, or with the assets of, any

149

Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the acquisition and holding of shares of common stock. Purchasers of shares of common stock have the exclusive responsibility for ensuring that their acquisition and holding of shares of common stock complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited transaction rules of ERISA, the Code or applicable Similar Laws. The sale of shares of common stock to a Plan is in no respect a representation by us or any of our affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

150

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our Class A common stock by a non-U.S. holder (as defined below) that holds our Class A common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

• banks, insurance companies or other financial institutions;

• tax-exempt or governmental organizations;

• qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);

• dealers in securities or foreign currencies;

• persons whose functional currency is not the U.S. dollar;

• “controlled foreign corporations,” “passive foreign investment companies” and corporations that accumulate earnings to avoid U.S. federal income tax;

• traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

• persons subject to the alternative minimum tax;

• partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

• persons deemed to sell our Class A common stock under the constructive sale provisions of the Code;

• persons that acquired our Class A common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

• certain former citizens or long-term residents of the United States; and

• persons that hold our Class A common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

151

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our Class A common stock that is not for U.S. federal income tax purposes a partnership or any of the following:

• an individual who is a citizen or resident of the United States;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our Class A common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our Class A common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our Class A common stock by such partnership.

Distributions

Distributions of cash or property on our Class A common stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will instead be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our Class A common stock (and will reduce such tax basis) and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Class A Common Stock.”

Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our Class A common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax (including backup withholding discussed below) if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

152

Gain on Disposition of Common Stock

Subject to the discussions below under “—Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our Class A common stock unless:

• the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

• the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

• our Class A common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes and as a result such gain is treated as effectively connected with a trade or business conducted by the non-U.S. holder in the United States.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).

With regard to the third bullet point above, generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our Class A common stock is and continues to be “regularly traded on an established securities market” (within the meaning of the U.S. Treasury regulations), only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the Class A common stock, more than 5% of our Class A common stock will be treated as disposing of a U.S. real property interest and will be taxable on gain realized on the disposition of our Class A common stock as a result of our status as a USRPHC. If our Class A common stock were not considered to be regularly traded on an established securities market, such holder (regardless of the percentage of stock owned) would be treated as disposing of a U.S. real property interest and would be subject to U.S. federal income tax on a taxable disposition of our Class A common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

NON-U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE FOREGOING RULES TO THEIR OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-

153

U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form).

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Class A common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our Class A common stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our Class A common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our Class A common stock and on the gross proceeds from a disposition of our Class A common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E), or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our Class A common stock.

INVESTORS CONSIDERING THE PURCHASE OF OUR CLASS A COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

154

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated                 , we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC are acting as representatives the following respective numbers of shares of Class A common stock:

Underwriter	Number of Firm Securities to be Purchased
Credit Suisse Securities USA LLC
Goldman Sachs & Co. LLC
Barclays Capital Inc.
RBC Capital Markets, LLC
UBS Securities LLC
Wells Fargo Securities, LLC
Piper Jaffray & Co.
Raymond James & Associates, Inc.
Seaport Global Securities LLC
Tudor, Pickering, Holt & Co. Securities, Inc.
Total	$

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of Class A common stock in the offering if any are purchased, other than those shares covered by the underwriters’ option to purchase additional shares described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. The offering of the shares of Class A common stock by the underwriters is subject to receipt and acceptance, and subject to the underwriters’ right to reject, any order in whole or in part.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to                  additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised to the extent the underwriters sell more than                  shares of Class A common stock in connection with this offering.

The underwriters propose to offer the shares of Class A common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $                 per share. The underwriters and selling group members may allow a discount of $                 per share on sales to other broker/dealers. After the initial public offering, the underwriters may change the public offering price and concession and discount to broker/dealers.

The following table summarizes the compensation and estimated expenses we will pay:

	Per Share		Total
	Without Option to Purchase Additional Shares	With Option to Purchase Additional Shares	Without Option to Purchase Additional Shares	With Option to Purchase Additional Shares
Underwriting Discounts and Commissions paid by us	$	$	$	$

The expenses of this offering that have been paid or are payable by us are estimated to be approximately $                 million (excluding underwriting discounts and commissions). We have also agreed to reimburse the underwriters for certain of their expenses incurred in connection with this offering in an amount up to $                .

155

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any shares of our Class A common stock or securities convertible into or exchangeable or exercisable for any shares of our Class A common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC for a period of 180 days after the date of this prospectus.

Our officers and directors and certain of our stockholders and employees have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our Class A common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our Class A common stock, whether any of these transactions are to be settled by delivery of our Class A common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC for a period of 180 days after the date of this prospectus.

Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, in their discretion, may release the Class A common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the Class A common stock and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC may consider, among other factors, the holder’s reasons for requesting the release and the number of shares of Class A common stock or other securities for which the release is being requested.

We have agreed to indemnify the several underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We have applied to list the shares of Class A common stock on the NYSE under the symbol “MNRL.”

In connection with the listing of the Class A common stock on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of                  beneficial owners.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price was determined by negotiations among us and the underwriters and will not necessarily reflect the market price of the Class A common stock following this offering. The principal factors that were considered in determining the initial public offering price included:

• the information presented in this prospectus and otherwise available to the underwriters;

• the history of, and prospects for, the industry in which we will compete;

• the ability of our management;

• the prospects for our future earnings;

• the present state of our development, results of operations and our current financial condition;

• the general condition of the securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded common stock of generally comparable companies.

We cannot assure you that the initial public offering price will correspond to the price at which the Class A common stock will trade in the public market subsequent to this offering or that an active trading market for the Class A common stock will develop and continue after this offering.

156

In connection with the offering the underwriters may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase in the underwriters’ option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in the underwriters’ option to purchase additional shares. The underwriters may close out any covered short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market.

• Syndicate covering transactions involve purchases of the Class A common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the option to purchase additional shares. If the underwriters sell more shares than could be covered by the option to purchase additional shares, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

• Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the Class A common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our Class A common stock or preventing or retarding a decline in the market price of the Class A common stock. As a result the price of our Class A common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE and, if commenced, may be discontinued at any time.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to the issuer and to persons and entities with relationships with the issuer for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships with the issuer. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

157

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

Directed Share Program

At our request, the underwriters have reserved up to 5% of the shares for sale at the initial public offering price to persons who are directors, director nominees, officers or employees, or who are otherwise associated with us through a directed share program. The number of shares available for sale to the general public will be reduced by the number of directed shares purchased by participants in the program. The sales of shares pursuant to the program will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, an underwriter of this offering. Except for certain of our officers, directors, director nominees and employees who have entered into lock-up agreements, each person allocated shares having an aggregate value of $1.0 million or more through the directed share program has agreed that, for a period of 30 days from the date of this prospectus, he or she will not, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, dispose of or hedge any shares purchased in the program or any securities convertible into or exchangeable for our Class A common stock with respect to shares purchased in the program. For certain officers, directors and employees purchasing shares through the directed share program, the lock-up agreements described in this “Underwriting” section shall govern with respect to their purchases. Any directed shares not purchased will be offered by the underwriters to the general public on the same basis as all other shares offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed shares.

Selling Restrictions

Canada

The shares may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the shares must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriter is not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

EEA restriction

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any shares which are the subject of the offering contemplated by this prospectus (the “Shares”) may not be made in that Relevant Member State except

158

that an offer to the public in that Relevant Member State of any Shares may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

(a) to legal entities which are qualified investors as defined under the Prospectus Directive;

(b) by the underwriters to fewer than 100, or, if the Relevant Member State has implemented the relevant provisions of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive; or

(c) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of Shares shall result in a requirement for Extraction or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” in relation to any Shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any Shares to be offered so as to enable an investor to decide to purchase any Shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

United Kingdom

Each underwriter has represented and agreed that:

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (the “FSMA”)) received by it in connection with the issue or sale of the shares in circumstances in which Section 21(1) of the FSMA does not apply to Extraction; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

Notice to United Kingdom Investors

This prospectus is only being distributed to and is only directed at (i) persons who are outside the United Kingdom or (ii) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (iii) high net worth companies, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). The Shares are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such Shares will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

Hong Kong

The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the

159

document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan, or the Financial Instruments and Exchange Law, and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the common stock has been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a) you confirm and warrant that you are either:

(i) a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

160

(ii) a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii) a person associated with the company under section 708(12) of the Corporations Act; or

(iv) a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(d) you warrant and agree that you will not offer any of the common stock for resale in Australia within 12 months of that common stock being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

Notice to Prospective Investors in Switzerland

This document as well as any other material relating to the shares of our common stock that are the subject of the offering contemplated by this prospectus do not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations. Our common stock will not be listed on the SWX Swiss Exchange and, therefore, the documents relating to our common stock, including, but not limited to, this document, do not claim to comply with the disclosure standards of the listing rules of SWX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SWX Swiss Exchange. Our common stock is being offered in Switzerland by way of a private placement, i.e., to a small number of selected investors only, without any public offer and only to investors who do not purchase shares of our common stock with the intention to distribute them to the public. The investors will be individually approached by us from time to time. This document as well as any other material relating to our common stock is personal and confidential and does not constitute an offer to any other person. This document may only be used by those investors to whom it has been handed out in connection with the offering described herein and may neither directly nor indirectly be distributed or made available to other persons without our express consent. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in (or from) Switzerland.

Notice to Prospective Investors in Chile

The shares are not registered in the Securities Registry (Registro de Valores) or subject to the control of the Chilean Securities and Exchange Commission (Superintendencia de Valores y Seguros de Chile). This prospectus supplement and other offering materials relating to the offer of the shares do not constitute a public offer of, or an invitation to subscribe for or purchase, the shares in the Republic of Chile, other than to individually identified purchasers pursuant to a private offering within the meaning of Article 4 of the Chilean Securities Market Act (Ley de Mercado de Valores) (an offer that is not “addressed to the public at large or to a certain sector or specific group of the public”).

161

LEGAL MATTERS

The validity of the shares our Class A common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Brigham Resources as of December 31, 2017 and 2016, and for the years then ended, and the balance sheet of Brigham Minerals as of June 29, 2018, which was the date of its formation, have been included herein and in the registration statement in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Estimates of our reserves and related future net cash flows related to our properties as of June 30, 2018 and December 31, 2017 and 2016 included herein and elsewhere in the registration statement were based upon reserve reports prepared by independent petroleum engineers, CG&A. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our Class A common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the Class A common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the Public Reference Room maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained from such office upon payment of a duplicating fee. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

As a result of this offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

162

INDEX TO FINANCIAL STATEMENTS

	Page
BRIGHAM MINERALS, INC.
Audited Balance Sheet
Report of independent registered public accounting firm		F-2
Balance sheet as of June 29, 2018		F-3
Notes to balance sheet		F-4
BRIGHAM MINERALS, INC. PREDECESSOR
Unaudited Historical Condensed Consolidated Financial Statements
Unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017		F-5
Unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018 and 2017		F-6
Unaudited condensed consolidated statements of members’ equity for the six months ended June 30, 2018		F-7
Unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2018 and 2017		F-8
Notes to unaudited condensed consolidated financial statements		F-9
Historical Consolidated Financial Statements
Report of independent registered public accounting firm		F-20
Consolidated balance sheets as of December 31, 2017 and 2016		F-21
Consolidated statements of operations for the years ended December  31, 2017 and 2016		F-22
Consolidated statements of comprehensive income for the years ended December 31, 2017 and 2016		F-23
Consolidated statements of members’ equity for the years ended December 31, 2017 and 2016		F-24
Consolidated statements of cash flows for the years ended December  31, 2017 and 2016		F-25
Notes to consolidated financial statements		F-26

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Brigham Minerals, Inc.:

Opinion on the Financial Statement

We have audited the accompanying balance sheet of Brigham Minerals, Inc. (the Company) as of June 29, 2018 and the related notes (collectively, the financial statement). In our opinion, the financial statement presents fairly, in all material respects, the financial position of the Company as of June 29, 2018 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

The financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statement, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statement. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement. We believe that our audit provides a reasonable basis for our opinion.

(signed) KPMG LLP

We have served as the Company’s auditor since 2013.

Dallas, Texas

October 29, 2018

F-2

BRIGHAM MINERALS, INC.

BALANCE SHEET

	June 29, 2018
Assets
Assets
Cash and cash equivalents	$	—
Total assets	$	—
Shareholders’ Equity
Shareholders’ Equity
Common stock, $.01 par value; authorized 1,000 shares, 1,000 issued and outstanding at June 29, 2018	$	10
Less receivable from Brigham Parent Holdings, L.P.		(10	)
Total shareholders’ equity	$	—

F-3

BRIGHAM MINERALS, INC.

NOTES TO BALANCE SHEET

1. Organization and Basis of Presentation

Brigham Minerals, Inc. (“Brigham Minerals”) is a Delaware corporation formed in June 2018 to become a holding company.

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Brigham Parent Holdings, L.P. has committed to contribute certain interests in Brigham Minerals, LLC as the initial sole shareholder. This contribution receivable is reflected as a reduction to equity. Separate Statements of Operations, Changes in Shareholders’ Equity and of Cash Flows have not been presented because Brigham Minerals has had no business transactions or activities to date.

2. Subsequent events

Brigham Minerals acquired an indirect interest in Brigham Resources, LLC (“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. As a result of such restructuring transactions, Brigham Minerals became wholly owned by certain entities affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a membership interest in Brigham Resources. The remaining outstanding membership interests of Brigham Resources remained with its other existing owners.

F-4

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2018			December 31, 2017
	(Restated)
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	1,590		$	6,886
Restricted cash		3,953			—
Accounts receivable		19,200			13,055
Prepaid expenses and other		1,483			987
Investment in equity securities		—			4,105
Total current assets		26,226			25,033
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property		214,865			168,691
Evaluated property		211,192			152,354
Less accumulated depreciation, depletion and amortization		(19,770	)		(14,210	)
Oil and gas properties—net		406,287			306,835
Other property and equipment		5,020			4,685
Less accumulated depreciation		(2,816	)		(2,493	)
Other property and equipment—net		2,204			2,192
Long-term derivative assets		16			—
Other assets, net		774			417
Total assets	$	435,507		$	334,477
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	3,592		$	4,791
Current derivative liabilities		657			121
Total current liabilities		4,249			4,912
Long-term debt		70,000			27,000
Other non-current liabilities		423			391
Non-current derivative liabilities		30			—
Members’ equity:
Members’ contributed capital		207,795			166,030
Accumulated other comprehensive income		—			682
Accumulated earnings		153,010			135,462
Total members’ equity		360,805			302,174
Total liabilities and members’ equity	$	435,507		$	334,477

F-5

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Restated)						(Restated)
	(In thousands, except per share data)
Revenues:
Mineral and royalty revenue	$	14,522		$	6,907		$	26,386		$	12,032
Lease bonus and other revenue		2,367			1,294			4,586			8,092
Total revenues		16,889			8,201			30,972			20,124
Other operating income:
(Loss) gain on sale of oil and gas properties, net		—			(18	)		—			94,558
Operating Expenses:
Gathering, transportation and marketing		912			356			2,007			668
Severance and ad valorem taxes		882			314			1,642			597
Depreciation, depletion and amortization		3,213			1,551			5,758			3,113
General and administrative		1,318			835			2,782			1,831
Total operating expenses		6,325			3,056			12,189			6,209
Net income from operations		10,564			5,127			18,783			108,473
Loss on derivative instruments, net		(555	)		—			(914	)		—
Interest expense, net		(652	)		(79	)		(1,126	)		(150	)
Gain on sale of equity securities		—			—			823			—
Other income, net		6			75			10			151
Income before income taxes		9,363			5,123			17,576			108,474
Income tax expense		12			99			28			750
Net income	$	9,351		$	5,024		$	17,548		$	107,724

F-6

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY

(UNAUDITED)

	Members’ Contributed Capital			Retained Earnings		Accumulated Other Comprehensive Income			Total Members’ Equity
	(in thousands)
Balance—December 31, 2017	$	166,030		$	135,462	$	682		$	302,174
Contributions		46,011			—		—			46,011
Distributions		(4,246	)		—		—			(4,246	)
Other comprehensive income		—			—		(682	)		(682	)
Net income (Restated)		—			17,548		—			17,548
Balance—June 30, 2018 (Restated)	$	207,795		$	153,010	$	—		$	360,805

F-7

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2018			2017
	(Restated)
	(In thousands)
Cash flows from operating activities
Net income	$	17,548		$	107,724
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,758			3,113
Amortization of debt issue costs		74			58
Deferred income taxes		31			148
Non-cash loss on derivative instruments, net		549			—
Gain on sale of equity securities		(823	)		—
Gain on sales of oil and gas properties		—			(94,558	)
Changes in operating assets and liabilities:
(Increase)/decrease in accounts receivable		(6,146	)		(1,999	)
(Increase)/decrease in other current assets		(496	)		(68	)
(Increase)/decrease in other deferred charges		(427	)		5
Increase/(decrease) in accounts payable and accrued liabilities		(1,169	)		(43	)
Other operating		—			910
Net cash provided by operating activities	$	14,899		$	15,290
Cash flows from investing activities
Acquisitions of oil and gas properties		(105,041	)		(30,531	)
Additions to other fixed assets		(334	)		(344	)
Proceeds from sale of oil and gas properties, net		125			111,031
Changes in restricted cash held in escrow for acquisitions		(3,953	)		—
Net cash (used in) provided by investing activities	$	(109,203	)	$	80,156
Cash flows from financing activities
Repayments of long-term debt		—			(15,000	)
Borrowings of long-term debt		43,000			5,000
Capital contributions		46,011			—
Capital distributions		—			(113,656	)
Loan closing costs		(3	)		(13	)
Net cash provided by (used in) financing activities	$	89,008		$	(123,669	)
(Decrease) increase in cash and cash equivalents		(5,296	)		(28,223	)
Cash and cash equivalents, beginning of period		6,886			33,960
Cash and cash equivalents, end of period	$	1,590		$	5,737
Supplemental disclosure of noncash activity:
Equity securities received		—		$	45,633
Equity securities distributed	$	4,246			—
Accrued capital expenditures	$	43		$	60
Vesting of A-M units		—		$	600

F-8

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Business and Basis of Presentation

Description of the Business

Brigham Resources, LLC (“Brigham Resources”), a Delaware limited liability company, was formed on March 28, 2013 as a holding company with no independent operations apart from its ownership of the subsidiaries described herein. Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, “Minerals Subsidiaries”), Delaware limited liability companies, were formed on October 17 and December 21, 2012, respectively, to pursue the acquisition of oil and natural gas mineral and royalty interests in liquids-rich resource plays in the continental United States (the “Minerals Business”). The Mineral Subsidiaries own nonproducing and producing mineral and royalty interests in 37 counties in Colorado, New Mexico, North Dakota, Oklahoma, Texas and Wyoming. Concurrent with the formation of Brigham Resources, on April 5, 2013, Brigham Resources purchased 100% of the common units of the Mineral Subsidiaries. Brigham Resources Management, LLC (“Brigham Management, LLC”), a Delaware limited liability company formed on March 28, 2013, provides administrative services to Brigham Resources and the Minerals Subsidiaries. References to “we,” “us” and “our” mean Brigham Resources.

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements of Brigham Resources are comprised of the financial statements of the Minerals Subsidiaries and Brigham Management, LLC and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The financial statements included herein reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. All intercompany account balances and transactions have been eliminated. These unaudited interim condensed consolidated financial statements do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements should be read in conjunction with our audited financial statements and notes for the year ended December 31, 2017, contained elsewhere in this prospectus. The results of operations for the three and six months ended June 30, 2018 are not necessarily indicative of the results to be expected for the full year.

Brigham Resources operates in one segment: oil and natural gas exploration and production. Historically, Brigham Resources has owned and operated two distinct lines of business through its subsidiaries:

• the Minerals Business through the Minerals Subsidiaries; and

• an upstream oil and gas exploration and production business (the “Upstream Business”) in the Southern Delaware Basin of West Texas (including interests in certain related gathering systems) through Brigham Resources Operating, LLC (“Brigham Operating”).

In February 2017, Brigham Operating completed the sale of substantially all of its oil and natural gas leasehold properties to an unrelated third-party purchaser. Following the sale, Brigham Operating’s only material assets have consisted of an ownership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering system located in the southern Delaware Basin. Brigham Resources plans to distribute to its members or their affiliates 100% of the equity interests in Brigham Operating. Accordingly, subsequent to such distribution Brigham Resources will no longer have any direct or indirect ownership interest in Brigham Operating. Therefore, the accompanying condensed consolidated financial statements of Brigham Resources exclude the assets, liabilities and results of operations of Brigham Operating for all periods presented.

F-9

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

Correction of Previously Issued Financial Statements

Management identified material misstatements in the previously issued condensed consolidated financial statements for the six months ended June 30, 2018 and an immaterial correction for the six months ended June 30, 2017. The misstatements for the six months ended June 30, 2018 related to the reporting of accrued revenues with respect to the payments we receive from operators and also with regard to the reporting of revenues generated prior to the close date of recently acquired properties. Management has evaluated the errors and determined the errors are material to the condensed consolidated financial statements for the six months ended June 30, 2018; therefore, Brigham Resources has restated its condensed consolidated financial statements for the six months ended June 30, 2018 to correct the misstatements. The effect of this restatement to the condensed consolidated financial statements for the three and six months ended June 30, 2018 is as follows:

	Three Months Ended June 30, 2018
	Reported		Restatement			Restated
Condensed Consolidated Statement of Operations
Royalty income	$	15,753	$	(1,231	)	$	14,522
Total revenue		18,120		(1,231	)		16,889
Gathering, transportation and marketing		943		(31	)		912
Severance and ad valorem taxes		980		(98	)		882
Depreciation, depletion and amortization		3,389		(176	)		3,213
Total operating expenses		6,630		(305	)		6,325
Net income from operations		11,490		(926	)		10,564
Income before taxes		10,289		(926	)		9,363
Net income		10,277		(926	)		9,351

	Six Months Ended June 30, 2018
	Reported			Restatement			Restated
Condensed Consolidated Balance Sheets
Accounts receivable	$	20,770		$	(1,570	)	$	19,200
Total current assets		27,796			(1,570	)		26,226
Accumulated depreciation, depletion and amortization		(20,019	)		249			(19,770	)
Oil and gas properties – net		406,038			249			406,287
Total assets		436,828			(1,321	)		435,507
Accounts payable and accrued liabilities		3,752			(160	)		3,592
Total current liabilities		4,409			(160	)		4,249
Accumulated earnings		154,171			(1,161	)		153,010
Total members’ equity		361,966			(1,161	)		360,805
Total liabilities and members’ equity		436,828			(1,321	)		435,507
Condensed Consolidated Statement of Operations
Royalty income		27,956			(1,570	)		26,386
Total revenue		32,542			(1,570	)		30,972
Gathering, transportation and marketing		2,063			(56	)		2,007
Severance and ad valorem taxes		1,746			(104	)		1,642
Depreciation, depletion and amortization		6,007			(249	)		5,758
Total operating expenses		12,598			(409	)		12,189
Net income from operations		19,944			(1,161	)		18,783
Income before taxes		18,737			(1,161	)		17,576
Net income		18,709			(1,161	)		17,548

F-10

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

	Six Months Ended June 30, 2018
	Reported			Restatement			Restated
Condensed Consolidated Statement of Members’ Equity
Retained earnings		154,171			(1,161	)		153,010
Total members’ equity		361,966			(1,161	)		360,805
Condensed Consolidated Statement of Cash Flows
Net income		18,709			(1,161	)		17,548
Depreciation and amortization		6,007			(249	)		5,758
(Increase) decrease in accounts receivable		(7,716	)		1,570			(6,146	)
Increase (decrease) in accounts payable and accrued liabilities	$	(1,009	)	$	(160	)	$	(1,169	)

In addition, we corrected the presentation of gains and losses on sales of assets, and we included these gains and losses in other operating income for all periods presented. This resulted in a decrease in previously reported operating expense and corresponding increase to previously reported operating income for the three and six months ended June 30, 2017 of $18,000 and $94 million, respectively. This correction did not impact the previously reported consolidated balance sheet as of December 31, 2017, or condensed consolidated statements of comprehensive income, members’ equity or cash flows for the three or six months ended June 30, 2017, and has been accounted for as an immaterial correction of an error.

2. Summary of Significant Accounting Policies

Significant Accounting Policies

Significant accounting policies are disclosed in Brigham Resources’ audited financial statements and notes for the year ended December 31, 2017, contained elsewhere in this prospectus. There have been no changes in such policies or the application of such policies during the six months ended June 30, 2018.

Recently Issued Accounting Standards

Brigham Minerals’ status as an emerging growth company under Section 107 of the JOBS Act 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, it will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Clarifying the Definition of a Business. This guidance assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. The new standard becomes effective for us on January 1, 2019 and is required to be adopted using a prospective approach. Although early application is permitted, we do not plan to adopt ASU-2017-01 early.

In November 2016, the FASB issued 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.

F-11

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

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 new standard becomes effective for us on January 1, 2019. Although early application is permitted, we do not plan to adopt the ASU early.

In February 2016, 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. The ASU will replace most existing lease guidance in GAAP when it becomes effective. The new standard becomes effective for us on January 1, 2020. Although early application is permitted, we do not plan to adopt the ASU early. The standard requires the use of the modified retrospective transition method. We are currently evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

In May, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 will be effective for us beginning on January 1, 2019 considering the one-year deferral provided by ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. The standard permits the use of either the full retrospective or modified retrospective transition method and early adoption is permitted. Brigham Resources intends to use the modified retrospective adoption approach and does not plan to early adopt. Brigham Resources is currently reviewing a representative sample of revenue contracts covering its material revenue streams that is designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to date, the implementation of the new standard is not anticipated to have a material impact on the consolidated financial statements. Brigham Resources is concurrently evaluating the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. Brigham Resources continues to evaluate the disclosure requirements of this new guidance and expects to fully complete its evaluation of the impacts of ASU 2014-09 to the consolidated financial statements and related disclosures by 2018 year end.

3. Oil and Gas Properties

Brigham Resources 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 consisted of the following:

	June 30, 2018			December 31, 2017
	(Restated)
	(in thousands, except per unit of production data)
Oil and gas properties, at cost, using the full cost method of accounting:
Not subject to depletion	$	214,865		$	168,691
Subject to depletion		211,192			152,354
Total oil and gas properties, at cost		426,057			321,045
Less accumulated depreciation, depletion, and amortization		(19,770	)		(14,210	)
Total oil and gas properties, net	$	406,287		$	306,835

F-12

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

Capitalized costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $3.1 million and $1.4 million for the three months ended June 30, 2018 and 2017, respectively, and $5.4 and $2.8 million for the six months ended June 30, 2018 and 2017, respectively. Average depletion of proved properties was $9.05 per Boe and $6.51 per Boe for the three months ended June 30, 2018 and 2017, respectively, and $8.61 per Boe and $7.92 per Boe for the six months ended June 30, 2018 and 2017, respectively.

Brigham Resources 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 production and general corporate overhead or similar activities. Capitalized costs were $0.6 million and $0.3 million for the three months ended June 30, 2018 and 2017, respectively, and $1.4 million and $0.6 million for the six months ended June 30, 2018 and 2017, respectively.

4. Acquisitions and Divestitures

In June 2018, Brigham Resources closed on the acquisition of certain mineral interests from an unrelated third-party in the Delaware Basin in Loving County, Texas and Lea County, New Mexico for $41 million, subject to customary post-closing adjustments. Brigham Resources funded the acquisition with capital contributions and borrowings under our prior revolving credit facility. The allocation of the purchase price was $22.8 million to evaluated properties and $18.2 million to unevaluated properties. In addition, during the three and six months ended June 30, 2018, Brigham Resources entered into a number of individually insignificant acquisitions of mineral and royalty interests from various sellers in Texas, Oklahoma and North Dakota, as reflected in the table below. The change in the oil and natural gas property balance is comprised of individually insignificant payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative expenses that were funded with capital contributions and borrowings under our prior revolving credit facility.

	Assets Acquired				Consideration Paid
	Evaluated		Unevaluated		Cash
	(in thousands)
Quarter Ended March 31, 2018	$	14,132	$	11,462	$	25,594
Quarter Ended June 30, 2018		21,903		16,588		38,491
Total Acquired	$	36,035	$	28,050	$	64,085

In June 2018, Brigham Resources entered into a definitive agreement with an unrelated third-party to acquire certain mineral interests in Reeves, Loving and Ward counties in the Delaware Basin for $24.3 million and closed on $22.0 million of the transaction in August 2018 and anticipates that the second closing will occur in November 2018.

Restricted cash includes deposits for the purchase of certain mineral and royalty interests as required under the related purchase and sale agreements. The $4.0 million of cash held in escrow as of June 30, 2018 is expected to be released in August 2018 at the closing of the related acquisitions.

On February 28, 2017, Brigham Operating and Brigham Resources Midstream, LLC, wholly owned subsidiaries of Brigham Resources, closed on the sale of substantially all of their Southern Delaware Basin leasehold and related assets, including certain mineral and royalty interests owned by Brigham Resources, to a

F-13

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

third-party public entity. The proceeds for mineral and royalty interests represented $156.7 million of the net adjusted sales price and consisted of cash of $111.1 million and shares valued at $45.6 million. The mineral and royalty interests sold represented approximately 12% in aggregate of Brigham Resources’ total proved reserves as of December 31, 2016. As a result of the sale, the relationship between capitalized costs and proved reserves was altered significantly and Brigham Resources recorded a gain of $94.6 million.

5. Derivative Instruments

Brigham Resources 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 Resources does not enter into derivative instruments for speculative or trading purposes.

Counterparties to the Minerals Subsidiaries’ derivative instruments who are also lenders under the Minerals Subsidiaries’ secured revolving credit facility allow the Minerals Subsidiaries to satisfy any need for margin obligations associated with derivative instruments where the Minerals Subsidiaries are in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Because the counterparties have investment grade credit ratings, Brigham Resources believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its derivative instruments. Although Brigham Resources does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties. As a result of all the Minerals Subsidiaries’ derivative contracts being in a liability position at June 30, 2018, Brigham Resources does not have any exposure related to nonperformance from its counterparties.

Concurrent with the termination of the prior revolving credit facility, we posted cash collateral of $1.4 million for our existing WTI fixed price swap contracts. We anticipate entering into swap intercreditor agreements between Owl Rock Capital Corporation (“Owl Rock”) and our hedge counterparties, at which time we would retract the cash collateral. See Note 7—Long-Term Debt.

As of June 30, 2018, Brigham Resources had certain WTI fixed price swap contracts based on the New York Mercantile Exchange (“NYMEX”) futures index. The fair values, notional quantities and weighted-average swap prices of these contracts as of December 31, 2017, are summarized in the table below.

Description & Production Period	Volume		Weighted Average Swap Price		Fair Value Asset/ (Liability) (in thousands)
	(Bbl)		($/Bbl)
Crude Oil Swaps:
July 2018—September 2018(1)		55,000	$	61.32	$	(542	)
October 2018—December 2018		15,000	$	67.59	$	(25	)
January 2019—March 2019		15,000	$	63.61	$	(56	)
April 2019—June 2019		15,000	$	63.61	$	(34	)
July 2019 — September 2019		15,000	$	63.61	$	(15	)
October 2019—December 2019		15,000	$	63.61	$	1
Total		130,000	$	63.10	$	(671	)

(1) Includes swaps for 10,000 Bbl valued as a liability of $0.1 million that matured on June 30, 2018 and will be settled in July, 2018.

F-14

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

Our derivative instruments are subject to master netting arrangements and are presented on a net basis in our condensed consolidated balance sheets. The following table summarizes the location and fair value of our derivative instruments as of June 30, 2018 and December 31, 2017 (in thousands):

Derivative Instruments	Balance Sheet Classification	Gross Amount Recognized		Less Group Amount of Offset		Net Amount Recognized
As of June 30, 2018
Derivative assets:
Commodity swaps	Non-current derivative assets	$	16	$	—	$	16
Derivative liabilities:
Commodity swaps	Current derivative liabilities	$	657	$	—	$	657
Commodity swaps	Non-current derivative liabilities	$	30			$	30
As of December 31, 2017
Derivative liabilities:
Commodity swaps	Current derivative liabilities	$	121	$	—	$	121

During the three and six months ended June 30, 2018, Brigham Resources had realized and unrealized losses on its oil swap contracts of $0.6 million and $0.9 million, respectively, included in loss on derivative instruments, net on its condensed consolidated statements of operations. No gains or losses were realized during the six months ended June 30, 2017.

6. Fair Value Measurements

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

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

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

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

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

F-15

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2018 and December 31, 2017 are as follows (in thousands):

	June 30, 2018
	Level 1		Level 2		Level 3		Total
Assets—commodity derivative instruments		—	$	16		—	$	16
Liabilities—commodity derivative instruments		—	$	687		—	$	687
	December 31, 2017
	Level 1		Level 2		Level 3		Total
Assets—investment in equity securities	$	4,105	$	—	$	—	$	4,105
Liabilities—commodity derivative instruments		—		121		—		121

Level 1 equity securities represent publicly traded securities valued using quoted market prices. During 2017, Brigham Resources received shares of publicly traded securities as partial proceeds from the sale of oil and gas properties discussed in Note 4 and classified them as available for sale. As of December 31, 2017, Brigham Resources had remaining available for sale securities with aggregate cost basis of $3.4 million and unrealized gains of $0.7 million, which is included in accumulated other comprehensive income (“AOCI”). The fair value of available for sale securities held by Brigham Resources as of December 31, 2017 was $4.1 million and is included in investment in equity securities on the accompanying condensed consolidated balance sheets. During the six months ended June 30, 2018, Brigham Resources had unrealized gains on available for sale securities of $0.1 million. All remaining available for sale securities were distributed during 2018 and, as a result, gains of $0.8 million were reclassified out of AOCI and included in gain on sale of equity investments on the accompanying condensed consolidated statement of operations.

Our derivative instruments consist of WTI fixed price swaps carried at fair value. 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.

Brigham Resources 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, 2018 and 2017.

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

Certain nonfinancial 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 operating and development costs, future commodity prices and a risk-adjusted discount rates, and are classified within Level 3.

F-16

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

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 prior revolving credit facility approximates fair value as interest rates on these instruments approximate current market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.

7. Long-Term Debt

Prior to its termination on July 27, 2018, the Minerals Subsidiaries maintained a secured revolving credit facility with a syndicate of financial institutions (the prior “revolving credit facility”), which had been amended periodically. The revolving credit facility had aggregate commitments of $150 million and a borrowing base of $70 million, subject to periodic redeterminations based on the Minerals Subsidiaries’ oil and natural gas reserves and other factors. The borrowing base was re-determined semi-annually with effective dates of May 1 and November 1. In addition, the Minerals Subsidiaries were permitted to request up to one additional redetermination of the borrowing base during any fiscal year. The borrowing base and outstanding borrowings were $70 million and $70 million, respectively, as of June 30, 2018 and $50 million and $27 million, respectively, as of December 31, 2017.

The outstanding borrowings under the prior revolving credit facility bore interest at a rate elected by the Minerals Subsidiaries that was equal to either an adjusted base rate, which was equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% or 3-month LIBOR plus 1.0%, or an adjusted LIBOR rate with an interest period selected by the Minerals Subsidiaries, in each case, plus the applicable margin. The applicable margin ranged from 1.50% to 2.50% in the case of the adjusted base rate and from 2.50% to 3.50% in the case of LIBOR, in each case, depending on the amount of the loan outstanding in relation to the borrowing base. The Minerals Subsidiaries were obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, depending on the amount of the loan outstanding in relation to the borrowing base. Loan principal was permitted to be repaid from time to time at the option of Minerals Subsidiaries without premium or penalty (other than customary LIBOR breakage). Loan principal was required to be paid back to the extent the loan amount exceeded the borrowing base at any time before maturity or the total outstanding balance upon the January 26, 2021 maturity date. The loan was secured by substantially all of the Minerals Subsidiaries’ assets.

The credit agreement governing the prior revolving credit facility contained various affirmative and negative covenants, including limiting additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements. Additionally, the credit agreement required the maintenance of quarterly financial ratios including total debt to EBITDAX not to exceed 4 to 1 and a ratio of current assets to current liabilities of no less than 1 to 1. Brigham Resources was in compliance with all financial covenants as of June 30, 2018 and December 31, 2017.

On July 27, 2018, the prior revolving credit facility was terminated in conjunction with a new term loan facility (our “term loan facility”) with Owl Rock as administrative agent and collateral agent. Brigham Resources used the proceeds from the term loan facility to repay the outstanding $70 million of principal under the prior revolving credit facility and to fund mineral and royalty acquisitions. Additionally, during the third quarter of 2018, Brigham Resources wrote off approximately $0.3 million of unamortized debt issuance costs that were

F-17

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

related to the prior revolving credit facility. Our term loan facility is subject to customary fees, guarantees of subsidiaries, restrictions and covenants, including certain restricted payments, and is collateralized by certain oil and natural gas properties of Brigham Resources.

Structure.    Our term loan facility provides for a $125 million initial term loan and a delayed draw term loan (“DDTL”) of $75 million, which will be subject to certain customary conditions. In addition, a $10 million revolving credit facility is available for general corporate purposes.

Interest.     Our term loan facility bears 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%. From and after the date of an underwritten public offering, each of the foregoing margins will decrease by 0.50% if at the end of the most recently completed fiscal quarter our total net leverage ratio (as defined in the credit agreement governing our term loan facility) is less than or equal to 2.00 to 1.00.

Maturity.    July 27, 2024.

Amortization.    The loans amortize in quarterly installments equal to, upon the consummation of an underwritten public offering, 1.00% per annum and, otherwise, 5.00% per annum (commencing with the quarter ending December 31, 2019), in each case, subject to certain requirements to prepay the outstanding balance of the loan with certain excess cash flows (as defined in the credit agreement governing our term loan facility).

As of July 31, 2018, we had $150 million of outstanding borrowings under our term loan facility. The credit agreement governing our term loan facility also requires us to maintain compliance with the following financial and collateral coverage ratios:

• an asset coverage ratio, which is the ratio of (a) the sum of (i) the present value of our and the other loan parties’ proved reserves (as set forth in the most recently delivered reserve report) that are subject to a mortgage in favor of the administrative agent under our term loan facility plus (ii) the Swap Mark-to-Market Value (as defined in the credit agreement) as of such date to (b) Consolidated Senior Secured First Lien Indebtedness (as defined in the credit agreement) as of such date of not less than 1.75 to 1.00.

• a total net leverage ratio, which is the ratio, on a pro forma basis, of (a) Consolidated Total Indebtedness (as defined in the credit agreement) as of such date less up to $25 million of cash and certain permitted investments to (b) two times our Consolidated EBITDA (as defined in the credit agreement) for the most recently completed Test Period (as defined in the credit agreement) of not more than (y) upon the consummation of an underwritten public offering, 4.00 to 1.00 as of the last day of any fiscal quarter or (z) otherwise, 5.50 to 1.00 commencing on September 30, 2018, which steps down quarterly to 4.00 to 1.00 as of December 31, 2019.

F-18

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

8. Commitments and Contingencies

Commitments

Brigham Resources leases office space under operating leases. Rent expense for the six months ended June 30, 2018 and 2017 was $0.1 million. Future minimum lease commitments under noncancelable operating leases at June 30, 2018 are presented below (in thousands):

Year	Commitment
2018	$	179
2019		436
2020		449
2021		461
2022		472
2023		160
Total	$	2,157

Contingencies

Brigham Resources 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 Resources records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Resources had no reserves for contingencies at June 30, 2018 and December 31, 2017.

9. Subsequent Events

In July 2018, Brigham Resources entered into a new lease for additional office space. Future minimum lease commitments under the noncancelable operating lease related to the additional office space is presented below (in thousands):

Year	Commitment
2019	$	97
2020		198
2021		204
2022		210
2023		216
Thereafter		109
Total	$	1,034

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers

Brigham Resources, LLC:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Brigham Resources, LLC (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, members’ equity, and cash flows for the years then ended and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Other Matters

Our audit was conducted for the purpose of forming an opinion on the financial statements as a whole. The supplementary oil and gas information included in note 11 is presented for the purposes of additional analysis and is not a required part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audit of the financial statements and, accordingly, we do not express an opinion or provide any assurance on it.

(signed) KPMG LLP

We have served as the Company’s auditor since 2013.

Dallas, Texas

July 17, 2018

F-20

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONSOLIDATED BALANCE SHEETS

	December 31,
	2017			2016
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,886		$	33,960
Accounts receivable		13,055			6,268
Prepaid expenses and other		987			943
Investment in equity securities		4,105			—
Total current assets		25,033			41,171
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property		168,691			162,591
Evaluated property		152,354			119,493
Less accumulated depreciation, depletion and amortization		(14,210	)		(9,009	)
Oil and gas properties—net		306,835			273,075
Other property and equipment		4,685			3,375
Less accumulated depreciation		(2,493	)		(1,759	)
Other property and equipment—net		2,192			1,616
Other assets, net		417			435
Total assets	$	334,477		$	316,297
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	4,791		$	703
Derivative instruments		121			—
Total current liabilities		4,912			703
Long-term bank debt		27,000			15,000
Deferred tax liability		391			96
Members’ equity:
Members’ contributed capital		166,030			280,648
Accumulated other comprehensive income		682			—
Accumulated earnings		135,462			19,850
Total members’ equity		302,174			300,498
Total liabilities and members’ equity	$	334,477		$	316,297

See accompanying notes to consolidated financial statements.

F-21

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2017			2016
	(in thousands)
Revenue:
Mineral and royalty revenue	$	30,066		$	14,046
Lease bonus and other revenue		10,842			7,187
Total revenue		40,908			21,233
Other operating income:
Gain on sale of oil and gas properties, net		94,551			—
Expenses:
Gathering, transportation and marketing		1,754			820
Severance and ad valorem taxes		1,601			629
Depreciation, depletion and amortization		6,955			4,913
General and administrative		3,935			3,751
Total operating expenses		14,245			10,113
Net income from operations		121,214			11,120
Loss on derivative instruments, net		(121	)		—
Interest expense, net		(556	)		(298	)
Loss on sale and distribution of equity securities		(4,222	)		—
Other income, net		305			476
Income before taxes		116,620			11,298
Income tax expense		1,008			50
Net income	$	115,612		$	11,248

See accompanying notes to consolidated financial statements.

F-22

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2017			2016
	(in thousands)
Net income	$	115,612		$	11,248
Other comprehensive income
Unrealized losses on available for sale equity securities, net		(3,540	)		—
Reclassification of losses on sale and distribution of available for sale equity securities		4,222			—
Other comprehensive income		682			—
Comprehensive income	$	116,294		$	11,248

See accompanying notes to consolidated financial statements.

F-23

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

	Members’ Contributed Capital			Retained Earnings		Accumulated Other Comprehensive Income		Total Members’ Equity
	(in thousands)
Balance—December 31, 2015	$	201,051		$	8,602	$	—	$	209,653
Contributions		79,597							79,597
Net income					11,248				11,248
Balance—December 31, 2016		280,648			19,850		—		300,498
Contributions		37,600							37,600
Distributions		(152,218	)						(152,218	)
Other comprehensive income							682		682
Net income					115,612				115,612
Balance—December 31, 2017	$	166,030		$	135,462	$	682	$	302,174

See accompanying notes to consolidated financial statements.

F-24

BRIGHAM RESOURCES, LLC

(Our Predecessor)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2017			2016
	(in thousands)
Operating Activities
Net income	$	115,612		$	11,248
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization		6,955			4,913
Amortization of debt issue costs		121			86
Deferred income taxes		295			50
Non-cash hedging loss, net		121			—
Loss on sale and distribution of equity securities		4,222			—
Gain on sales of oil and gas properties		(94,551	)		—
Changes in operating assets and liabilities:
(Increase)/decrease in accounts receivable		(6,787	)		(723	)
(Increase)/decrease in other current assets		(44	)		(352	)
Increase/(decrease) in accounts payable and accrued liabilities		3,956			(1,355	)
Other operating		(499	)		616
Net cash provided by operating activities	$	29,401		$	14,483
Investing Activities
Additions to oil and gas properties		(101,437	)		(91,319	)
Additions to other fixed assets		(1,311	)		(507	)
Proceeds from sale of oil and gas properties, net		111,024			—
Proceeds from sale of equity securities		17,896			—
Net cash provided by (used in) investing activities	$	26,172		$	(91,826	)
Financing Activities
Payments of long-term debt		(15,000	)		(18,000	)
Borrowing of long-term debt		27,000			33,000
Capital contributions		37,000			78,382
Capital distributions		(131,544	)		—
Loan closing costs		(103	)		(242	)
Net cash (used in) provided by financing activities	$	(82,647	)	$	93,140
(Decrease) increase in cash and cash equivalents		(27,074	)		15,797
Cash and cash equivalents, beginning of year		33,960			18,163
Cash and cash equivalents, end of year	$	6,886		$	33,960
Supplemental disclosure of noncash activity:
Equity securities received	$	45,633		$	—
Equity securities distributed	$	(20,092	)	$	—
Accrued capital expenditures	$	73		$	24
Vesting of A-M units	$	600		$	600

See accompanying notes to consolidated financial statements.

F-25

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Business

Brigham Resources, LLC (“Brigham Resources”) was incorporated in Delaware on March 28, 2013 to pursue the acquisition, exploration and development of onshore domestic oil and natural gas properties and the acquisition of producing and nonproducing oil and natural gas mineral and royalty interests. Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”) were incorporated in the State of Delaware on October 17 and December 21, 2012, respectively, to pursue the acquisition of nonproducing and producing oil and natural gas mineral and royalty interests. Brigham Minerals owns producing and nonproducing mineral and royalty interests in various counties in Colorado, Oklahoma, North Dakota, Texas, Wyoming, Montana and Pennsylvania. On April 5, 2013, Brigham Resources purchased 100% of the common units of the Minerals Subsidiaries. References to “we,” “us” and “our” mean Brigham Resources.

2. Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of Brigham Resources are comprised of the financial statements of the Minerals Subsidiaries and Brigham Resources Management, LLC and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. All intercompany account balances and transactions have been eliminated. Brigham Resources operates in one segment: oil and natural gas exploration and production.

Brigham Resources has historically owned and operated two distinct lines of business through its subsidiaries:

• the Minerals Business through the Minerals Subsidiaries; and

• an upstream oil and gas exploration and production business (the “Upstream Business”) in the Southern Delaware Basin of West Texas (including interests in certain related gathering systems) through Brigham Resources Operating, LLC (“Brigham Operating”).

In February 2017, Brigham Operating completed the sale of substantially all of its oil and natural gas properties to an unrelated third-party purchaser, following which Brigham Operating’s only material assets have consisted of an ownership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering system located in the southern Delaware Basin. Brigham Resources plans to distribute to its members or their affiliates 100% of the equity interests in Brigham Operating. Accordingly, subsequent to such distribution Brigham Resources will no longer have any direct or indirect ownership interest in Brigham Operating. Accordingly, the accompanying consolidated financial statements of Brigham Resources exclude the assets, liabilities and results of operations of Brigham Operating.

Subsequent to the issuance of our December 31, 2017 consolidated financial statements we corrected the amount of equity securities distributed, included in the supplemental disclosure of non-cash activity, from $37,988 to $20,092 (in thousands) for the year ended December 31, 2017. Additionally, we corrected the presentation of gains and losses on sales of assets, and we included these gains and losses in other operating income for all periods presented. This resulted in a $94 million decrease to previously reported operating expenses and a corresponding increase to previously reported operating income for the year ended December 31, 2017. These corrections did not impact the previously reported consolidated balance sheet as of December 31, 2017 or statements of comprehensive income, members’ equity or cash flows and have been accounted for as immaterial corrections of errors.

F-26

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Emerging Growth Company Status

As a company with less than $1.07 billion in revenues during its last fiscal year, Brigham Minerals qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.

Brigham Minerals will remain an “emerging growth company” until as late as the last day of Brigham Minerals’ 2023 fiscal year, or until the earliest of (i) the last day of the fiscal year in which Brigham Minerals has $1.07 billion or more in annual revenues; (ii) the date on which Brigham Minerals becomes a “large accelerated filer” (the fiscal year-end on which the total market value of Brigham Minerals’ common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which Brigham Minerals issues more than $1.0 billion of non-convertible debt over a three-year period.

As a result of Brigham Minerals’ election to avail itself of certain provisions of the JOBS Act, the information that Brigham Minerals provides may be different than the information provided by other public companies.

Use of Estimates

The preparation of consolidated financial statements in conformity 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 consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.

The accompanying consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGLs reserves that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Brigham Resources’ reserve estimates are determined by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments and revenue accruals.

Cash and Cash Equivalents

Brigham Resources considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Receivables

Receivables consist of royalty income due from operators for oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of our properties and the operator, in turn, remits

F-27

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

payment to us. Receivables from third parties for which we did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates are based upon historical actual data if available or, otherwise, on engineering estimates. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.

Brigham Resources routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Brigham Resources did not record any allowance for doubtful accounts for the years ended December 31, 2017 and 2016.

Concentration of Credit Risk and Significant Customers

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

	December 31,
	2017			2016
Noble Energy, Inc.		13	%		—
Continental Resources, Inc.		10	%		15	%
Anadarko Petroleum Corp.		—			13	%

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.

Investments in Equity Securities

Brigham Resources classifies its equity securities as available-for-sale, and as such, they are carried at fair value. Changes in fair value of available-for-sale securities are reported as a component of other comprehensive income. Losses may be recognized within the consolidated statement of operations when a decline in value is determined to be other-than-temporary. Brigham Resources uses the average cost method to determine the realized gain or loss for each sale or distribution of available-for-sale securities.

Financial Instruments

Brigham Resources’ financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities, investments in equity securities and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The equity securities are publicly traded and are valued using quoted market prices.

F-28

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The fair values of Brigham Resources’ derivative assets and liabilities are based on 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, volatility factors and credit risk adjustments.

• The carrying amount of long-term debt associated with borrowings outstanding under Brigham Resources’ prior revolving credit facility approximates fair value as borrowings bear interest at variable market rates. See “Note 5—Fair Value Measurements,” “Note 6—Derivative Instruments” and “Note 7—Long-Term Bank Debt.”

Derivative Instruments

In the normal course of business, Brigham Resources is exposed to certain risks, including changes in the prices of oil, natural gas and NGLs and interest rates. Brigham Resources has historically entered into derivative contracts to manage its exposure to these risks. Brigham Resources’ risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. Brigham Resources does not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. Brigham Resources does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within loss on derivative instruments, net.

Oil and Gas Properties

Brigham Resources 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 and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.

Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by net equivalent proved reserves at the beginning of the period.

Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition and leasehold costs and capitalized interest. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties in 2017 and 2016.

F-29

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

Natural gas volumes are converted to barrels of oil equivalent (Boe) at the rate of six thousand cubic feet (Mcf) of natural gas to one barrel (Bbl) of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

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 lower of cost or fair value of unevaluated properties (the ceiling limitation). A ceiling limitation is calculated at each reporting period. If total capitalized costs, net of accumulated DD&A are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. 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. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using the 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). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas.

As of December 31, 2017 and 2016, the full cost ceiling value of our reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12 months ended December 31, 2017 and 2016 of $51.34 and $42.60, respectively, per barrel for oil, adjusted by area for energy content, transportation fees and regional price differentials and the unweighted arithmetic average first-day-of-the-month price for the 12 months ended December 31, 2017 and 2016 of $2.99 and $2.47 respectively, per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. Using these prices, the net book value of oil and natural gas was above the ceiling limitation and no write-off was necessary.

Income Taxes

Brigham Resources is treated as a partnership for federal income tax purposes. As a result, the net taxable income of Brigham Resources and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no federal tax provision has been recorded in the consolidated financial statements of Brigham Resources. Brigham Resources is subject to Texas margin tax based on revenue generated from operations within the state. During the year ended December 31, 2017, Brigham Resources recorded current tax expense of $0.7 million and deferred tax expense of $0.3 million. During the year ended December 31, 2016, Brigham Resources recorded deferred tax expenses of $0.1 million and no current tax expenses. Brigham Resources had $0.4 million and $0.1 million recorded as deferred tax liability related to the Texas margin tax at December 31, 2017 and 2016, respectively. The deferred tax liability is due primarily to differences between the tax basis of oil and natural gas properties and their reported amounts in Brigham Resources’ financial statements.

F-30

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Revenue Recognition

Royalty interests represent the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when title passes to the purchaser. Royalty interests have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property.

Brigham Resources recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

Pricing of oil, natural gas and NGL sales from Brigham Resources’ properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. Brigham Resources has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from its properties.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Brigham Resources earns lease bonus revenues and lease extension revenues (collectively referred to as “lease bonus revenue”) from leasing mineral interests to exploration and production companies in exchange for a royalty interest. Lease bonus revenues are recognized when received, at which time Brigham Resources gives up the right to develop the land itself or to lease it to another party.

Debt Issuance Cost

Other assets include capitalized debt issuance costs of $0.4 million and $0.4 million, net of accumulated amortization of $0.3 million and $0.1 million as of December 31, 2017 and 2016, respectively. Debt issuance costs were incurred in connection with establishing and amending credit facilities for Brigham Resources and are amortized over the term of the credit facilities using the straight-line method, which approximates the effective interest rate method. Amortization expense for debt issue costs was $0.2 million and $0.1 million for the years ended December 31, 2017 and 2016, respectively, and is included in interest expense, net in the consolidated statements of operations.

Recently Issued Accounting Standards

Brigham Minerals’ status as an emerging growth company under Section 107 of the JOBS Act 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, it will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Clarifying the Definition of a Business. This guidance assists in determining whether a

F-31

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. We expect that the adoption of this ASU could have a material impact on future consolidated financial statements as goodwill would not be recorded for acquisitions that are not considered to be businesses.

In November 2016, the FASB issued 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 new standard becomes effective for us on January 1, 2019. Although early application is permitted, we do not plan to adopt the ASU early.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which applies to all entities that are required to present a statement of cash flows. The ASU provides guidance on eight specific cash flow issues. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. For all other entities, the ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We are evaluating the impact, if any, that the adoption of this update will have on our consolidated financial statements and related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses—Measurement of Credit Losses on Financial Instruments. The ASU significantly changes how entities measure credit losses for most financial assets and certain other instruments that aren’t measured at fair value through net income. The standard will replace today’s “incurred loss” approach with an “expected loss” model for instruments measured at amortized cost and require entities to record allowances for available-for-sale debt securities rather than reduce the carrying amount, as they do today under the other-than-temporary impairment model. We will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings for annual reporting periods beginning after December 15, 2020, and interim periods within annual periods beginning after December 15, 2021. We are currently evaluating the impact, if any, that the adoption of this update will have on our consolidated financial statements and related disclosures.

In February 2016, 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. The ASU will replace most existing lease guidance in GAAP when it becomes effective. The new standard becomes effective for us on January 1, 2019. Although early application is permitted, we do not plan to adopt the ASU early. The standard requires the use of the modified retrospective transition method. We are currently evaluating the impact, if any, that the adoption of this update will have on our consolidated financial statements and related disclosures.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU changes to the current GAAP model primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. Under the new standard, all equity

F-32

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

investments in unconsolidated entities (other than those accounted for using the equity method of accounting) will generally be measured at fair value through earnings. There will no longer be an available-for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily determinable fair values. The new standard becomes effective for us on January 1, 2019. Although early application is permitted, we do not plan to adopt the ASU early. The standard requires the use of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year in which the guidance is adopted. We are currently evaluating the impact, if any, that the adoption of this update will have on our consolidated financial statements and related disclosures.

In May, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 will be effective for us beginning on January 1, 2019 considering the one-year deferral provided by ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. We have not selected a transition method and are evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

3. Oil and Gas Properties

Oil and gas properties consisted of the following:

	December 31,
	2017			2016
	(in thousands, except per unit of production data)
Oil and gas properties, at cost, using the full cost method of accounting:
Not subject to depletion	$	168,691		$	162,591
Subject to depletion		152,354			119,493
Total oil and gas properties, at cost		321,045			282,084
Less accumulated depreciation, depletion and amortization		(14,210	)		(9,009	)
Total oil and gas properties, net	$	306,835		$	273,075
Full cost pool depletion per barrel of oil equivalent	$	7.25		$	8.36

Costs not subject to depletion at December 31, 2017 are as follows, by the year in which such costs were incurred (in thousands):

	Total		2017		2016		Prior
Property acquisition costs	$	168,691	$	73,635	$	16,283	$	78,773

Oil and natural gas properties are depleted on a unit of production basis. Depletion expense for the years ended December 31, 2017 and 2016 was $6.2 million and $4.3 million, respectively.

Brigham Resources capitalizes certain overhead expenses and other internal costs attributable to acquisition of mineral and royalty interests as part of its investment in oil and gas properties over the periods benefitted by

F-33

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

these activities. Capitalized costs do not include any costs related to production and general corporate overhead or similar activities. Capitalized costs for the years ended December 31, 2017 and 2016 were $2.1 million and $1.4 million, respectively.

4. Acquisitions and Divestitures

In August 2017, Brigham Resources acquired certain mineral and royalty interests in the Delaware Basin for $29.2 million. Brigham Resources funded the acquisition with capital contributions. The allocation of the purchase price was $20.5 million to unevaluated properties and $8.7 million to evaluated properties.

In addition, during 2017 and 2016, Brigham Resources entered into a number of individually insignificant acquisitions. The change in the oil and natural gas property balance is comprised of individually insignificant payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative capital expenditures.

On February 28, 2017, Brigham Operating and Brigham Resources Midstream, LLC, wholly owned subsidiaries of Brigham Resources, closed on the sale of substantially all of their Southern Delaware Basin leasehold and related assets, including certain royalty interests owned by the Minerals Subsidiaries, to a third-party public entity. The proceeds for royalty interests owned by the Minerals Subsidiaries represented $156.7 million of the net adjusted sales price and consisted of cash of $111.1 million and shares valued at $45.6 million. The royalty interests sold represented approximately 12% (unaudited) in aggregate of the Minerals Subsidiaries’ total proved reserves as of December 31, 2016. As a result of the sale, the relationship between capitalized costs and proved reserves was altered significantly and Brigham Resources recorded a gain of $94.6 million.

5. 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.

F-34

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 are as follows (in thousands):

	December 31, 2017
	Level 1		Level 2		Level 3		Total
Assets—investment in equity securities	$	4,105	$	—	$	—	$	4,105
Liabilities—commodity derivative contracts		—		121		—		121

Brigham Resources had no financial assets and liabilities measured at fair value on a recurring basis at December 31, 2016.

Level 1 equity securities represent publicly traded securities valued using quoted market prices. During 2017, Brigham Resources received shares of publicly traded securities as partial proceeds from the sale of oil and gas properties discussed in Note 4 and classified them as available for sale. During 2017, Brigham Resources sold a portion of the shares and received proceeds of $17.9 million, which was distributed to investors, along with additional shares with a fair value at the time of distribution of $20.1 million. As a result of the sales and distributions, unrealized losses of $4.2 million were reclassified out of accumulated other comprehensive income (“AOCI”) and included in loss on sale of equity investments on the accompanying consolidated statement of operations. As of December 31, 2017, Brigham Resources has remaining available for sale securities with aggregate cost basis of $3.4 million and unrealized gains of $0.7 million, which is included in AOCI. The fair value of available for sale securities held by Brigham Resources as of December 31, 2017 was $4.1 million and is included in investment in equity securities on the accompanying consolidated balance sheets.

Our derivative contracts consist of oil swaps carried at fair value. Commodity derivative contracts 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.

Brigham Resources had no transfers into or out of Level 1 and no transfers into or out of Level 2 for the year ended December 31, 2017.

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

Certain nonfinancial 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 operating and development costs, future commodity prices and a risk-adjusted discount rate, 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

F-35

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

amount of debt outstanding pursuant to the our prior revolving credit facility approximates fair value as interest rates on these instruments approximate current market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.

6. Derivative Instruments

Brigham Resources has in the past used 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. Brigham Resources does not enter into derivative instruments for speculative or trading purposes.

As of December 31, 2017, Brigham Resources had certain oil swap contracts based on the New York Mercantile Exchange (“NYMEX”) futures index. The fair values, notional quantities and weighted-average swap prices of these contracts as of December 31, 2017, are summarized in the table below. Brigham Resources had no derivative contracts as of December 31, 2016.

Volumes are presented in barrels (“Bbls”).

Description & Production Period	Volume		Weighted Average Swap Price		Fair Value (in thousands)
	(Bbl)		($/Bbl)
Crude Oil Swaps:
January 2018 — March 2018		45,000	$	59.00	$	63.00
April 2018 — June 2018		30,000	$	58.63	$	39.00
July 2018 — September 2018		15,000	$	57.68	$	19.00
Total		90,000	$	58.65	$	121.00

Our derivative contracts are subject to master netting arrangements and are presented on a net basis in our consolidated balance sheets. The following table summarizes the location and fair value of our derivative contracts as of December 31, 2017 (in thousands):

Derivative Contracts	Balance Sheet Classification		Gross Amount Recognized		Less Group Amount of Offset		Net Amount Recognized
Derivative liabilities:
Commodity swaps		Derivative instruments – current	$	121	$	—	$	121

During the year ended December 31, 2017, Brigham Resources had unrealized losses on its oil swap contracts of $0.1 million included in loss on derivative instruments, net on its consolidated statements of operations. No gains or losses were realized during the years ended December 31, 2017 and 2016.

7. Long-Term Bank Debt

The Mineral Subsidiaries as co-borrowers (the “Minerals Borrowers”) maintain a secured revolving credit facility with a syndicate of financial institutions, which has been amended periodically. The revolving credit facility has a borrowing base of $150 million, subject to periodic redeterminations based on the Minerals Borrowers’ oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined

F-36

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

semi-annually with effective dates of May 1 and November 1. In addition, Minerals Borrowers may request up to one additional redetermination of the borrowing base during any fiscal year. The borrowing base and outstanding borrowings were $50 million and $27 million, respectively, as of December 31, 2017 and $30 million and $15 million, respectively, as of December 31, 2016.

The outstanding borrowings under the revolving credit facility bear interest at a rate elected by the Minerals Borrowers that is equal to either an adjusted base rate, which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% or 3-month LIBOR plus 1.0%, or an adjusted LIBOR rate with an interest period selected by Brigham Resources, in each case, plus the applicable margin. The applicable margin ranges from 1.50% to 2.50% in the case of the adjusted base rate and from 2.50% to 3.50% in the case of LIBOR, in each case, depending on the amount of the loan outstanding in relation to the borrowing base. Minerals Borrowers are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, depending on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be repaid from time to time at the option of Brigham Resources without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be paid back to the extent the loan amount exceeds the borrowing base at any time before maturity or the total outstanding balance upon the January 26, 2021 maturity date. The loan is secured by substantially all of the Minerals Borrowers’ assets.

The credit agreement governing the revolving credit facility contains various affirmative and negative covenants, including limiting additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements. Additionally, the credit agreement requires the maintenance of quarterly financial ratios including total debt to EBITDAX not to exceed 4 to 1 and a ratio of current assets to current liabilities of no less than 1 to 1. Brigham Resources was in compliance with all financial covenants as of December 31, 2017 and 2016.

8. Commitments and Contingencies

Lease obligations

Brigham Resources leases office space under operating leases. Rent expense for each of the years ended December 31, 2017 and 2016 was $0.2 million. Future minimum lease commitments under noncancelable operating leases at December 31, 2017 are presented below (in thousands):

Year	Commitment
2018	$	229
2019		236
2020		243
2021		208
Total	$	916

Contingencies

Brigham Resources 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 Resources records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Resources had no reserves for contingencies at December 31, 2017 and 2016.

F-37

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Related-Party Transactions

Brigham Land Management (“BLM”) provides Brigham with land brokerage services. The services are provided at market prices and are periodically verified by third-party quotes. BLM is owned by Vince Brigham, an advisor to Brigham and brother of Ben M. Brigham, founder of Brigham Resources and Executive Chairman of the Board. For the years ended December 31, 2017 and 2016, Brigham Resources paid BLM $0.6 million and $0.7 million, respectively for land brokerage services. At December 31, 2017 and 2016, the liabilities recorded for services performed by BLM during the respective periods were immaterial.

Brigham Exploration Company (“BEXP”), owned by Ben M. Brigham, leases some of Brigham Resources’ acreage at market rates. For the year ended December 31, 2017, BEXP paid Brigham Resources $0.6 million. There were no payments for the years ended December 31, 2016.

Employee Benefit Plans

We sponsor a 401(k) tax-deferred savings plan for our employees. We match 100% of each employee’s contributions, up to 6% of the employee’s total compensation. Brigham Resources may also contribute additional amounts at its discretion. Brigham Resources contributed $0.1 million to the 401(k) plan for each of the years ended December 31, 2017 and 2016.

10. Subsequent Events

Subsequent to December 31, 2017, Brigham Resources entered into a new lease for an extended office space. Future minimum lease commitments under noncancelable operating leases after the execution of the new office lease are presented below (in thousands):

Year	Commitment
2018	$	98
2019		200
2020		206
2021		253
2022		472
Thereafter		160
Total	$	1,389

In April 2018, Brigham Resources signed purchase and sale agreements to purchase mineral interests in Texas and New Mexico for approximately $41 million, subject to customary post-closing adjustments. The transaction closed in June 2018.

11. Reserves and Related Financial Data (SMOG)—Unaudited

Oil and Natural Gas Reserves

Proved reserves represent quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods. Proved reserves were estimate in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

F-38

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The reserves at December 31, 2017 and 2016 presented below were prepared by CG&A. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in various fields in Texas, New Mexico, Oklahoma, Colorado, Wyoming, North Dakota, Montana and Pennsylvania. All of the proved reserves are located in the continental United States.

	Crude Oil (MBbl)			Natural Gas (Mmcf)			NGL (MBbl)			Total (MBoe)
Proved reserve quantities, December 31, 2015		4,311			16,662			1,596			8,684
Sales of minerals-in-place
Extensions and discoveries		18			11			3			23
Acquisitions		2,970			5,367			708			4,573
Revisions of previous estimates		137			1,906			139			595
Production		(262	)		(955	)		(90	)		(512	)
Proved reserve quantities, December 31, 2016		7,174			22,991			2,356			13,363
Sales of minerals-in-place		(1,291	)		(815	)		(200	)		(1,627	)
Extensions and discoveries		1,548			6,012			709			3,259
Acquisitions		2,141			9,380			1,116			4,820
Revisions of previous estimates		(394	)		2,601			108			147
Production		(454	)		(1,768	)		(109	)		(858	)
Proved reserve quantities, December 31, 2017		8,724			38,401			3,980			19,104
Proved developed reserve quantities:
December 31, 2015		1,094			5,073			472			2,411
December 31, 2016		1,772			6,077			628			3,413
December 31, 2017		2,804			13,028			1,185			6,160
Proved undeveloped reserve quantities:
December 31, 2015		3,217			11,589			1,124			6,273
December 31, 2016		5,402			16,914			1,728			9,950
December 31, 2017		5,920			25,373			2,795			12,944

Changes in proved reserves that occurred during 2017 were primarily due to:

• the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 4,820 MBoe of additional proved reserves;

• well additions, extensions and discoveries of approximately 3,259 MBoe, as 854 horizontal well locations were converted from probable and possible to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests;

• the divestiture of 1,627 MBoe through one sale of mineral and royalty interests located in the Permian Basin;

• positive volume revisions of approximately 2,581 MBoe attributable primarily to increased recovery in close proximity to our mineral and royalty interests, partially offset by negative revisions of approximately 2,434 MBoe, attributable primarily to operator development timing and revision of existing proved locations.

Changes in proved reserves that occurred during 2016 were primarily due to:

• the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 4,573 MBoe of additional proved reserves; and

• positive revisions of approximately 595 MBoe in proved reserves, primarily attributable to continuous activity and improved recovery on our mineral and royalty interests.

F-39

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Standardized Measure of Discounted Future Net Cash Flows

Guidelines prescribed in FASB’s Accounting Standards Codification (“ASC”) Topic 932 Extractive Industries—Oil and Gas, have been followed for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect Brigham Resources’ expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. The standardized measure excludes federal income taxes as Brigham Resources is a limited liability company and not subject to federal income taxes; however, Brigham Resources is subject to state taxes.

The following summary sets forth the future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932:

	For the Year Ended December 31,
	2017			2016
	(in thousands)
Future crude oil, natural gas and NGL sales	$	595,874		$	354,193
Future severance and ad valorem taxes		(40,225	)		(25,357	)
Future Texas margin tax expense		(1,151	)		(686	)
Future net cash flows		554,498			328,150
10% annual discount		(238,030	)		(142,398	)
Standardized measure of discounted future net cash flows	$	316,468		$	185,752

The following prices were used in the determination of standardized measure:

	December 31,
	2017		2016
Oil (per Bbl)	$	51.34	$	42.60
Natural gas (per MMBtu)		2.99		2.47

These prices were based on the 12-month arithmetic average first-of-month West Texas Intermediate (“WTI”) price of oil and Henry Hub price of natural gas. The NGL pricing varied by basin at 30% to 40% of WTI. All prices have been adjusted for transportation, quality, basis differentials and post-production costs.

F-40

BRIGHAM RESOURCES, LLC

(Our Predecessor)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The principal sources of change in the standardized measure of discounted future net cash flows are:

	For the Year Ended December 31,
	2017			2016
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	185,752		$	129,902
Changes in the year resulting from:
Sales, less production costs		(26,711	)		(12,597	)
Revisions of previous quantity estimates		4,894			5,409
Extensions, discoveries and other additions		56,511			382
Net change in prices and production costs		30,565			(18,008	)
Accretion of discount		18,612			12,990
Purchase of reserves in place		79,190			68,790
Divestitures of reserves in place		(26,742	)		—
Net change in Texas Margin Tax		(298	)		(366	)
Timing differences and other		(5,305	)		(750	)
Standardized measure of discounted future net cash flows, end of year	$	316,468		$	185,752

Capitalized oil and natural gas costs

The aggregate amounts of costs capitalized for oil and natural gas producing activities and related aggregate amounts of accumulated depletion follow:

	December 31,
	2017			2016
	(in thousands)
Oil and gas properties, at cost, using the full cost method of accounting:
Not subject to depletion	$	168,691		$	162,591
Subject to depletion		152,354			119,493
Total oil and gas properties, at cost		321,045			282,084
Less accumulated depreciation, depletion and amortization		(14,210	)		(9,009	)
Total oil and gas properties, net	$	306,835		$	273,075

Costs incurred in oil and natural gas activities

The following costs were incurred in oil and natural gas producing activities:

	Year Ended December 31,
	2017		2016
	(in thousands)
Acquisition of properties
Unevaluated	$	50,224	$	39,854
Evaluated		51,862		51,995
Total	$	102,086	$	91,849

F-41

ANNEX A

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:

Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC’s Regulation S-X, Rule 4-10(a)(2).

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

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. Installation of permanent equipment for production of oil, natural gas or NGLs, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Delineation. The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas and NGLs. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

A-1

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.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

Estimated ultimate recovery or EUR. The sum of reserves remaining as of a given date and cumulative production as of that date.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

Formation. A layer of rock that has distinct characteristics that differs from nearby rock.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a mineral or royalty interest is owned.

Held by production. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil, natural gas or NGLs.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

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.

MMBbl. One million barrels of crude oil, condensate or NGLs.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

Net production. Production on our properties calculated net to our royalty interests.

Net revenue interest. The net royalty, overriding royalty, production payment and net profits interests in a particular tract or well.

A-2

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.

Play. A geographic area with hydrocarbon potential.

Pooling. An operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Possible Reserves. Reserves that are less certain to be recovered than probable reserves.

Present value of future net revenues or PV-10. The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

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.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

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 area. The part of a property to which proved reserves have been specifically attributed.

Proved developed reserves. Reserves that can be expected to be recovered through (i) 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 (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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).

A-3

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. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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.

Resources. Quantities of oil, natural gas and NGLs estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Spot market price. The cash market price without reduction for expected quality, transportation and demand adjustments.

Spud. Commenced drilling operations on an identified location.

A-4

Standardized measure. Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil, natural gas and NGL properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

Success rate. The percentage of wells drilled that produce hydrocarbons in commercial quantities.

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.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Wellbore. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

Working interest. The right granted to the lessee of a property to develop, produce and own oil, natural gas, NGLs or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover. Operations on a producing well to restore or increase production.

A-5

Until                 , 2018 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the shares of Class A common stock offered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

SEC registration fee	$	*
FINRA filing fee		*
NYSE listing fee		*
Accounting fees and expenses		*
Legal fees and expenses		*
Printing and engraving expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment

Item 14. Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he or she is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him or her in connection with such action, suit or proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that limit the liability of our directors and officers for monetary damages to the fullest extent permitted by the DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except liability:

• for any breach of the director’s duty of loyalty to our company or our stockholders;

• for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law;

• under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or

• for any transaction from which the director derived an improper personal benefit.

II-1

Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.

In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities

In connection with our incorporation in June 2018 under the laws of the State of Delaware, we issued 1,000 shares of our common stock to an affiliate of Warburg Pincus in exchange for membership interests in Brigham Resources. These securities were offered and sold by us in reliance upon the exemption from the registration requirements provided by Section 4(a)(2) of the Securities Act. These shares will be redeemed for nominal value in connection with our reorganization.

Item 16. Exhibits and Financial Statement Schedules

(a) Exhibits.

Exhibit Number	Description
*1.1	Form of Underwriting Agreement
**3.1	Certificate of Incorporation of Brigham Minerals, Inc.
*3.2	Form of Amended and Restated Certificate of Incorporation of Brigham Minerals, Inc.
**3.3	Bylaws of Brigham Minerals, Inc.
*3.4	Form of Amended and Restated Bylaws of Brigham Minerals, Inc.
*4.1	Form of Class A Common Stock Certificate
*4.2	Form of Registration Rights Agreement
*4.3	Form of Stockholders’ Agreement
*5.1	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
*10.1†	Form of Brigham Minerals, Inc. 2018 Long-Term Incentive Plan

II-2

Exhibit Number	Description
*10.2	Form of Brigham Minerals Holdings, LLC First Amended and Restated Limited Liability Company Agreement
*10.3†	Form of Indemnification Agreement between Brigham Minerals, Inc. and each of the directors and officers thereof
**10.4	First Lien Credit Agreement, dated as of July 27, 2018, by and among Brigham Resources, LLC, Brigham Minerals, LLC, Owl Rock Capital Corporation, as first lien administrative agent and first lien collateral agent, Owl Rock Capital Advisors LLC, as the lead arranger and bookrunner, and the lenders and issuing banks party thereto
10.5	Contribution Agreement, dated as of July 16, 2018, by and among Brigham Parent Holdings, L.P., Brigham Minerals, Inc., Warburg Pincus Private Equity (E&P) XI (Brigham), LLC, Warburg Pincus XI (E&P) Partners-B (Brigham), LLC, Warburg Pincus Energy (E&P) (Brigham) LLC, WP Energy Partners (E&P) (Brigham), LLC and Warburg Pincus Energy (E&P) Partners-B (Brigham), LLC
*21.1	Subsidiaries of Brigham Minerals, Inc.
*23.1	Consent of KPMG LLP
*23.2	Consent of KPMG LLP
*23.3	Consent of Cawley, Gillespie & Associates, Inc.
*23.4	Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
*24.1	Power of Attorney (included on the signature page of this Registration Statement)
**99.1	Cawley, Gillespie & Associates, Inc., Summary of Reserves of Brigham Resources, LLC at December 31, 2017
**99.2	Cawley, Gillespie & Associates, Inc., Summary of Reserves of Brigham Resources, LLC at December 31, 2016
99.3	Cawley, Gillespie & Associates, Inc. Summary of Reserves of Brigham Resources, LLC at June 30, 2018

* To be filed by amendment.

** Previously filed.

† Compensatory plan or arrangement.

(b) Financial Statement Schedules. Financial statement schedules are omitted because the required information is not applicable, not required or included in the financial statements or the notes thereto included in the prospectus that forms a part of this registration statement.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless

II-3

in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Austin, State of Texas, on                     , 2018.

BRIGHAM MINERALS, INC.
By:
Name:	Robert M. Roosa
Title:	Chief Executive Officer and Director

Each person whose signature appears below appoints Robert M. Roosa and Blake C. Williams, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any registration statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities on                     , 2018.

Signature	Title
Ben M. Brigham	Executive Chairman
Robert M. Roosa	Chief Executive Officer and Director (Principal Executive Officer)
Blake C. Williams	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Harold D. Carter	Director
John Holland	Director
W. Howard Keenan, Jr.	Director
James R. Levy	Director

II-5

Signature	Title
Richard Stoneburner	Director
John R. Sult	Director

II-6