S-1 1 d588341ds1.htm S-1 S-1
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Index to Financial Statements

As filed with the Securities and Exchange Commission on March 18, 2019

Registration No. 333-                

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

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

Class A Common Stock, par value $0.01 per share

  $100,000,000   $12,120

 

 

(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.

 

 

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.

 

 

 


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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                     , 2019

            Shares

 

LOGO

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                     , 2019.

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                     , 2019.


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4 LOGO


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LOGO

All figures as of December 31, 2018

Rigs per 100K NRA figures as of three months ended December 31, 2018; 64 rigs *100,000 NRA / 68,800 NRA % of DUCs figures based on 806 Brigham identified DUCs relative to the EIA DUC count in the Permian, SCOOP/STACK, DJ, and Williston Basins; as of December 31, 2018

Organic Inventory calculated as 11,648 Undeveloped Locations / 748 2017 Wells Spud

 


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Index to Financial Statements

 

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

     61  

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

     63  

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     65  

BUSINESS

     84  

MANAGEMENT

     110  

EXECUTIVE COMPENSATION

     117  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     125  

CORPORATE REORGANIZATION

     129  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     134  

DESCRIPTION OF CAPITAL STOCK

     138  

SHARES ELIGIBLE FOR FUTURE SALE

     144  

CERTAIN ERISA CONSIDERATIONS

     146  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     149  

UNDERWRITING

     153  

LEGAL MATTERS

     160  

EXPERTS

     160  

WHERE YOU CAN FIND MORE INFORMATION

     160  

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                     , 2019 (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.

 

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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.

 

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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., the issuer in this offering (together with its wholly owned subsidiaries, “Brigham Minerals”), 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 December 31, 2018 have been audited by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineers, and the estimates of our proved, probable and possible reserves as of December 31, 2017 have been prepared by CG&A. 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 11,648 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

 

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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 38 of the most highly active counties for horizontal drilling in the continental United States. According to RS Energy Group (“RSEG”), as of December 31, 2018, operators have deployed 60% of the horizontal rig fleet, and 68% of the liquids-focused horizontal rig fleet, in the continental United States in these same 38 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 approximately 68,800 net royalty acres at December 31, 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 48% compound annual growth rate, or CAGR, from the beginning of 2013 through December 31, 2018, despite crude oil prices decreasing substantially during that same time period, as illustrated by the following chart.

 

LOGO

Since inception, we have executed on our technically driven, disciplined acquisition approach and have closed 1,292 transactions with third-party mineral and royalty interest owners as of December 31, 2018. We have increased our mineral and royalty interests from approximately 10,200 net royalty acres as of December 31, 2013, to approximately 68,800 net royalty acres as of December 31, 2018, which represents a 47% 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.

 

     2012      2013      2014      2015      2016      2017      2018      Total  

Net Royalty Acres (NRAs) Acquired

     500        9,700        17,300        7,200        9,800        9,400        14,900        68,800  

Number of Acquisitions

     15        313        380        152        121        110        201        1,292  

Average NRAs per Acquisition

     33        31        46        47        81        85        74        53  

NRAs at Period End

     500        10,200        27,500        34,700        44,500        53,900        68,800        68,800  

By targeting core, top-tier mineral acreage, our interests have continued to see rapid development with a total of approximately 748 horizontal wells spud on our mineral and royalty interests during 2017. This

 

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significant activity has similarly translated into rapid production growth with our production volumes growing approximately 65% from 2017 to 2018. Further, our production volumes are comprised of high-value liquids with 70% of our volumes for the twelve months ended December 31, 2018 composed of crude oil and natural gas liquids (“NGLs”), which represents 88% 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 99% increase in our royalty revenue from 2017 to 2018. We expect to see future organic growth in our production, revenue and free cash flow from 806 drilled but uncompleted horizontal wells (“DUCs”) across our interests and approximately 685 horizontal drilling permits as of December 31, 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 December 31, 2018, there have been an average of 43 horizontal rigs across our acreage, developing an average 1,600 net mineral acres, which we believe provides visibility toward future production growth.

 

Average Quarterly Rigs on Acreage   Average Quarterly NMA Under Development
LOGO   LOGO

In addition to existing near-term development, our permitted horizontal drilling locations represent only approximately 6% of the remaining proved, probable and possible undeveloped horizontal drilling locations incorporated by CG&A in our reserve report as of December 31, 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 94%, 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 748 horizontal wells spud on our acreage during 2017 and our 11,648 total gross undeveloped horizontal drilling locations as of December 31, 2018, we believe we have 16 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

     409        4,127        10     748        7,131        10

Wells Turned to Production

     311        4,075        8     597        6,753        9

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, our Executive Chairman, Ben (Bud) Brigham formed Brigham Exploration Company (“Brigham Exploration”), where it oversaw the

 

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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. Brigham Exploration 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 December 31, 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 December 31, 2018, our mineral and royalty interests consisted of approximately 48,100 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 17.9%. Typically, within the minerals industry, mineral owners standardize ownership to a 12.5%, or 1/8th, royalty interest, which is referred to as a “net royalty acre.” Our net mineral acres standardized to a 1/8th royalty equate to approximately 68,800 net royalty acres. When standardized on a 100% royalty basis, these approximately 68,800 net royalty acres equate to approximately 8,600 “100% royalty acres.” Our approximately 68,800 net royalty acres are located within 1,367 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 approximately 1,356,000 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 December 31, 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)
 

48,100

     17.9     68,800        8,600        1,356,000        0.6

 

(1)

Standardized to a 1/8th royalty (i.e., 48,100 net mineral acres * 17.9% / 12.5%).

 

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(2)

Standardized to a 100% royalty (i.e., 68,800 net royalty acres * 12.5%).

(3)

Calculated as number of 100% royalty acres per gross DSU acre (i.e., 8,600 100% royalty acres / 1,356,000 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 December 31, 2018.

 

LOGO

In addition, the following table summarizes certain information regarding our primary focus areas. Our average daily net production for the three months ended December 31, 2018 was comprised 55% of oil production, 28% of natural gas production and 17% of NGL production.

 

Basin

   Acreage as of December 31, 2018     Gross
Horizontal
Producing Well
Count as of
December 31,
2018(4)
     Average Daily Net
Production
for Three
Months Ended

December  31,
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

     11,600        20.7     19,200        2,400        229,000        1.0     469        1,982  

Midland

     2,600        15.4     3,200        400        58,000        0.7     104        197  

SCOOP

     5,900        18.4     8,700        1,090        167,000        0.7     262        467  

STACK

     6,800        17.8     9,700        1,210        156,000        0.8     211        563  

DJ

     12,100        15.9     15,400        1,920        165,000        1.2     838        817  

Williston

     5,200        16.3     6,800        850        470,000        0.2     1,379        436  

Other

     3,900        18.6     5,800        730        111,000        0.7     92        118  
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     48,100        17.9     68,800        8,600        1,356,000        0.6     3,355        4,579  
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

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

 

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Note:

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

(1)

Standardized to a 1/8th 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 December 31, 2018, according to RSEG, there were approximately 236 and 165 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 December 31, 2018, according to RSEG, there were approximately 32 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 December 31, 2018, according to RSEG, there were approximately 70 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 December 31, 2018, according to RSEG, there were approximately 30 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.

 

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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 December 31, 2018, according to RSEG, there were approximately 54 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 December 31, 2018, as reflected in our reserve report audited by CG&A, we have identified 11,648 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 47% 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

     3,844        33     40.0        40

Midland Basin

     787        7     6.7        7

SCOOP

     1,021        9     7.2        7

STACK

     1,776        15     16.6        17

DJ Basin

     1,681        14     21.7        22

Williston

     1,619        14     2.9        3

Other

     920        8     5.5        5
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     11,648        100     100.5       

 

100

 

 

Note: Individual amounts may not total due to rounding.

 

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Additionally, the following table provides a detailed summary of our inventory of horizontal drilling locations as of December 31, 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

     1,673        2,036        202        8.3        10.1        19.9  

Wolfcamp B

     912        981        243        3.8        4.0        10.6  

3rd BS/WC XY

     538        663        171        3.1        3.9        3.9  

2nd Bone Spring

     336        354        108        3.1        3.3        1.8  

Avalon

     144        163        63        2.3        2.6        0.6  

Other

     241        261        64        3.8        4.1        3.2  
  

 

 

    

 

 

             

 

 

 

Total

     3,844        4,458        307        12.5        14.5        40.0  

Midland Basin

                 

Wolfcamp A

     193        244        62        3.1        3.9        1.7  

Wolfcamp B

     195        252        58        3.4        4.3        1.7  

Lower Spraberry

     302        326        55        5.5        5.9        2.4  

Other

     97        106        26        3.7        4.1        1.0  
  

 

 

    

 

 

             

 

 

 

Total

     787        928        72        10.9        12.9        6.7  

SCOOP

                 

Woodford

     754        1,029        155        4.9        6.6        5.1  

Springer

     267        328        79        3.4        4.2        2.0  
  

 

 

    

 

 

             

 

 

 

Total

     1,021        1,357        155        6.6        8.8        7.2  

STACK

                 

Woodford

     919        1,021        150        6.1        6.8        8.2  

Meramec

     857        1,036        134        6.4        7.7        8.4  
  

 

 

    

 

 

             

 

 

 

Total

     1,776        2,057        168        10.6        12.2        16.6  

DJ Basin

                 

Niobrara

     1,248        2,022        185        6.7        10.9        16.2  

Codell

     433        659        139        3.1        4.7        5.5  
  

 

 

    

 

 

             

 

 

 

Total

     1,681        2,681        185        9.1        14.5        21.7  

Williston Basin

                 

Bakken

     743        1,659        340        2.2        4.9        1.2  

Three Forks

     876        1,537        340        2.6        4.5        1.7  
  

 

 

    

 

 

             

 

 

 

Total

     1,619        3,196        343        4.7        9.3        2.9  
  

 

 

    

 

 

             

 

 

 

Other

     920        1,035        137        6.7        7.6        5.5  
  

 

 

    

 

 

             

 

 

 

Grand Total

     11,648        15,712        1,367        8.5        11.5        100.5  
  

 

 

    

 

 

             

 

 

 

 

Note: Individual amounts may not total due to rounding.

(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 a 100% net revenue interest in a single gross well.

 

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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.

 

LOGO

 

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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 December 31, 2018.

 

     Percentage as of December 31, 2018  

Operator

   Total
Portfolio
     Delaware      Midland      SCOOP      STACK      DJ
Basin
     Williston      Other  

Anadarko Petroleum

     10%        16%        —          —          —          15%        —          —    

Noble Energy

     9%        14%        —          —          —          16%        —          —    

Encana(1)

     6%        —          2%        22%        19%        *        5%        17%  

Continental Resources

     5%        —          —          45%        2%        —          14%        18%  

Devon Energy

     4%        1%        —          —          24%        —          —          *  

Marathon Oil

     4%        —          —          20%        14%        —          1%        2%  

Pioneer Natural Resources

     4%        —          56%        —          —          —          —          —    

XTO

     3%        6%        2%        —          —          —          6%        12%  

Cimarex Energy

     3%        4%        —          —          11%        —          —          3%  

Whiting Petroleum

     3%        —          —          —          —          13%        4%        —    

Extraction Oil and Gas

     3%        —          —          —          —          12%        —          —    

Halcon Resources

     2%        6%        —          —          —          —          2%        —    

EOG Resources

     2%        1%        —          *        —          9%        4%        —    

Patriot Resources

     2%        6%        —          —          —          —          —          —    

Diamondback Energy

     2%        4%        11%        —          —          —          —          —    

Concho Resources

     2%        5%        1%        —          —          —          —          —    

PDC Energy

     2%        1%        —          —          —          7%        —          —    

Chevron Corporation

     2%        4%        4%        —          —          —          —          —    

Verdad Oil and Gas

     2%        —          —          —          —          7%        —          —    

Occidental Petroleum

     2%        4%        *        —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Subtotal

     72%        72%        76%        87%        70%        79%        36%        52%  

Other Operators

     28%        28%        24%        13%        30%        21%        64%        48%  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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 Encana Corporation’s acquisition of Newfield Exploration.

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 68,800 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 December 31, 2018, there were 806 DUCs across our acreage position, representing 13% of the DUCs estimated by the U.S. Energy Information Administration (the “EIA”) in our primary focus areas (as defined by the EIA, Anadarko, Bakken, Niobrara and Permian). 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 3,355 producing horizontal wells on our gross DSU

 

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acreage over the period. Over the twelve months ended December 31, 2018, there were an average of 43 rigs deployed across our acreage, with an average of approximately 1,600 net mineral acres under development per month. Additionally, operators continue to actively permit our interests, with approximately 90 new gross drilling permits issued per month over the last 12 months and a total of approximately 685 existing gross permitted drilling locations yet to be drilled across our gross DSU acreage as of December 31, 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 38 selected counties that we consider to be some of the most economically prospective in the country, with 60% of the entire horizontal rig fleet in the continental United States active within those counties as of December 31, 2018. Based on an assumed $6 million per well, we estimate that operators deployed approximately $47.2 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 approximately 68,800 net royalty acres as of December 31, 2018 since January 1, 2013, we estimate that the pro forma production volumes net to our interests would have grown at an approximate 48% compound annual growth rate from the beginning of 2013 through December 31, 2018, despite average crude oil prices as of December 31, 2018 decreasing by 34% 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 December 31, 2018, we estimate that 73% 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.

 

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Since inception, we have sourced and originated a significant number of potential transactions and, through our rigorous underwriting and evaluation process, closed 1,292 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 2018, we increased our mineral and royalty interests by 28% or approximately 14,900 net royalty acres. In addition, 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, any remaining available borrowings under our term loan facility or any other credit 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 30 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 1,292 transactions. Through December 31, 2018, our team has assembled approximately 68,800 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

 

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Index to Financial Statements
 

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.

 

   

Multi-year drilling inventory in the core of four active liquids-rich resource basins. As of December 31, 2018, we had interests in approximately 3,355 producing horizontal wells across 1,367 identified DSUs, or an average of 2.5 producing horizontal wells per DSU. As reflected in our reserve report audited by CG&A, 11,648 horizontal drilling locations are yet to be drilled by operators across those 1,367 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”), Encana Corporation (“Encana”) 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 Anadarko, Noble, Encana and Continental, as well as other best-in-class operators throughout our core areas. As of December 31, 2018, we have exposure to the top five 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 December 31, 2018, we estimate that 73% 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 Equity Holdings, 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

 

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which this prospectus forms a part. As a result of the July 2018 restructuring, Brigham Minerals became wholly owned by an entity 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.

On November 20, 2018, Brigham Resources underwent a second series of restructuring transactions that are collectively referred to in this prospectus as the “November 2018 restructuring.” In the November 2018 restructuring, Brigham Resources became a wholly owned subsidiary of Brigham LLC, which is a wholly owned subsidiary of Brigham Equity Holdings, LLC (“Brigham Equity Holdings”), and Brigham Equity Holdings became wholly owned by the Existing Owners, directly or indirectly through Brigham Minerals. As a result of the foregoing transactions, there was no change in the control or economic interests of the Existing Owners in Brigham Resources, although their ownership became 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 and Brigham Minerals (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, directly or indirectly, the net proceeds of this offering to Brigham LLC in exchange for an additional number of Brigham LLC Units such that Brigham Minerals holds, directly or indirectly, a total number of Brigham LLC Units equal to the number of shares of Class A common stock outstanding following 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;

 

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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 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.”

 

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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):

 

LOGO

 

 

(1)

Certain of the interests of our management in Brigham LLC will be held indirectly through Brigham Equity Holdings. Brigham Equity Holdings will directly own              Brigham LLC Units, representing an approximate         % interest in Brigham LLC. 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.

 

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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 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 $58 billion in private equity assets under management. The firm’s active portfolio of more than 180 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 18 private equity funds, which have invested more than $73 billion in over 855 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 an independently owned and operated asset management firm that was founded in 1991, dedicated to making private equity investments in the energy sector. Yorktown has raised twelve energy funds totaling more than $8.5 billion that has been invested in over 120 companies. Headquartered in New York, the firm makes primarily growth capital investments in the business of oil and natural gas production, pipelines, gathering systems and processing/fractionation plants, and to a lesser extent, energy-related manufacturing and services. Most investments are domiciled in North America with all investment properties being located onshore. Investing both as general partners and limited partners, the individual Yorktown partners combine to be among the largest investors in each fund.

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;

 

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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 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

 

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royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, a number of our operators have announced a reduction in projected capital expenditures for 2019.

 

   

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

 

   

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, including recent proposed legislation and ballot initiatives in Colorado, could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

 

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

 

   

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.

 

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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

 

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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 December 31, 2018, we had $175 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

 

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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—2019 Long Term Incentive Plan”).

 

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Summary Historical and Pro Forma Financial Data

Brigham Minerals was formed in June 2018 and has limited 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, and summary pro forma financial data for Brigham Minerals. The summary historical consolidated financial data of our predecessor as of and for the years ended December 31, 2017 and 2018 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma statement of operations and balance sheet data as of and for the year ended December 31, 2018 has been prepared to give pro forma effect to (i) the reorganization transactions described under “—Corporate Reorganization” and (ii) this offering and the application of the net proceeds therefrom as if each had been completed on January 1, 2018, in the case of the statement of operations data, and on December 31, 2018, in the case of the balance sheet data. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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 and the pro forma financial statements of Brigham Minerals included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

     Brigham Minerals
Predecessor Historical
     Brigham Minerals
Pro Forma
 
     Year Ended
December 31,
     Year Ended
December 31,
 
         2018              2017              2018      
                   (unaudited)  
    

(In thousands)

 

Statement of Operations Data:

        

Revenue:

        

Mineral and royalty revenue

   $ 59,758      $ 30,066      $                

Lease bonus and other revenue

     7,506        10,842     
  

 

 

    

 

 

    

 

 

 

Total revenue

     67,264        40,908     
  

 

 

    

 

 

    

 

 

 

Other operating income:

        

Gain on sale of oil and gas properties, net

     —          94,551     
  

 

 

    

 

 

    

 

 

 

Operating expense:

        

Gathering, transportation and marketing

     3,944        1,754     

Severance and ad valorem taxes

     3,536        1,601     

Depreciation, depletion and amortization

     13,915        6,955     

General and administrative

     6,638        3,935     
  

 

 

    

 

 

    

 

 

 

Total operating expense

     28,033        14,245     
  

 

 

    

 

 

    

 

 

 

 

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     Brigham Minerals
Predecessor Historical
    Brigham Minerals
Pro Forma
 
     Year Ended
December 31,
    Year Ended
December 31,
 
         2018             2017             2018      
                 (unaudited)  
    

(In thousands)

 

Operating income

     39,231       121,214    
  

 

 

   

 

 

   

 

 

 

Other income (expense):

      

Gain/(Loss) on derivative instruments, net

     424       (121  

Interest expense, net

     (7,446     (556  

Gain (Loss) on sale and distribution of equity securities

     823       (4,222  

Other income, net

     110       305    
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     33,142       116,620    
  

 

 

   

 

 

   

 

 

 

Income tax (benefit)/expense

     (220     1,008    
  

 

 

   

 

 

   

 

 

 

Net income

   $ 33,362     $ 115,612     $                
  

 

 

   

 

 

   

 

 

 

Non-controlling interest

      

Net income attributable to common stockholders

      

Net income per share attributable to common stockholders

      

Basic

      

Diluted

      

Weighted-average number of shares

      

Basic

      

Diluted

      

Other Financial Data:

      

Adjusted EBITDA(1)

     53,146       33,618    

Adjusted EBITDA ex lease bonus(1)

     45,640       22,776    

Balance Sheet Data:

      

Cash and cash equivalents

   $ 31,985     $ 6,886     $    

Total assets

     554,026       334,477    

Long-term debt, including current maturities

     170,705       27,000    

Total liabilities

     176,474       32,303    

Total equity

     377,552       302,174    

 

(1)

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”).

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.

 

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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     Brigham Minerals
Pro Forma
 
    Year Ended
December 31,
    Year Ended
December 31,
 
            2018                     2017                     2018          
                (unaudited)  
   

(in thousands)

 

Reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to net income:

     

Net income

  $ 33,362     $ 115,612     $                

Add:

     

Depreciation, depletion and amortization

    13,915       6,955    

Interest expense, net

    7,446       556    

Loss on sale and distribution of equity securities

          4,222    

Loss on derivative instruments, net

          121    

Income tax expense

          1,008    

Less:

     

Gain on derivative instruments, net

    424          

Other income, net

    110       305    

Gain on sale of oil and gas properties

          94,551    

Gain on sale and distribution of equity securities

    823          

Income tax benefit

    220          
 

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 53,146     $ 33,618     $    
 

 

 

   

 

 

   

 

 

 

Less:

     

Lease bonus

    7,506       10,842    
 

 

 

   

 

 

   

 

 

 

Adjusted EBITDA ex lease bonus

  $ 45,640     $ 22,776     $    
 

 

 

   

 

 

   

 

 

 

 

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Summary Reserve Data

The following table sets forth estimates of our net proved, probable and possible oil, natural gas and NGL reserves as of December 31, 2018 based on a reserve report audited 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 December 31, 2018 using the provisions of the SEC rule regarding reserve estimation regarding a historical twelve-month pricing average applied prospectively.

 

     December 31, 2018(1)  

Estimated proved developed reserves:

  

Oil (MBbls)

     6,067  

Natural gas (MMcf)

     21,735  

NGLs (MBbls)

     1,898  
  

 

 

 

Total (MBoe)

     11,588  

Estimated proved undeveloped reserves:

  

Oil (MBbls)

     6,923  

Natural gas (MMcf)

     30,062  

NGLs (MBbls)

     3,220  
  

 

 

 

Total (MBoe)

     15,153  

Estimated proved reserves:

  

Oil (MBbls)

     12,990  

Natural gas (MMcf)

     51,797  

NGLs (MBbls)

     5,118  
  

 

 

 

Total (MBoe)

     26,741  

Estimated probable reserves:

  

Oil (MBbls)(2)

     14,854  

Natural gas (MMcf)(2)

     66,682  

NGLs (MBbls)(2)

     7,560  
  

 

 

 

Total (MBoe)(2)

     33,528  

Estimated possible reserves:

  

Oil (MBbls)(2)

     10,302  

Natural gas (MMcf)(2)

     29,775  

NGLs (MBbls)(2)

     3,545  
  

 

 

 

Total (MBoe)(2)

     18,810  

Oil—WTI posted price per Bbl

     65.66  

Natural gas—Henry Hub spot price per Mcf

     3.12  

 

(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 $65.66 per barrel as of December 31, 2018 was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 22% to 41% of the WTI posted price. For gas volumes, the average Henry Hub spot price of $3.12 per MMBtu as of December 31, 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 proved properties are $61.31 per barrel of oil, $23.98 per barrel of NGL and $2.51 per Mcf of gas as of December 31, 2018.

(2)

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

 

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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

 

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price for West Texas Intermediary (“WTI”) light sweet crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $107.95 per barrel in June 2014, 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 $6.24 per MMBtu in January 2018.

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. In particular, a number of our operators have announced a reduction in projected capital expenditures for 2019.

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, 2018, we received revenue from over 100 operators, with approximately 60% 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. Furthermore, our operators may reduce capital expenditures devoted to exploration, development and production on our properties, which could negatively impact revenues we receive. For example, a number of our operators have announced a reduction in projected capital expenditures for 2019 and such reduction may affect their development activities on our properties. 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;

 

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

 

   

the selection of technology;

 

   

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

 

   

the rate of production of the reserves.

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

 

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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. Additionally, actual production from wells may be less than expected. For example, a number of operators have recently announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. 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.

 

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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.

 

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

As of December 31, 2018, only 11,587 MBoe of our total estimated reserves were proved developed reserves. The remaining 15,153 MBoe, 33,528 MBoe and 18,809 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,

 

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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 December 31, 2018 were audited by CG&A and our estimates of proved, probable and possible reserves and related valuations as of December 31, 2017 were prepared by CG&A. CG&A conducted a detailed review of all of our properties for the period covered by its reserve 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, 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

 

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estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from our reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (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.” In particular, a number of our operators have announced a reduction in projected capital expenditures for 2019. 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

 

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be reversed in a subsequent period even if higher oil, natural gas and NGL prices increase the cost center ceiling applicable to the subsequent period. If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.

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

 

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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.

 

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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, but not limited to:

 

   

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.

 

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including recent proposed legislation and ballot initiatives in Colorado, 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. In addition, the Colorado state legislature has from time to time considered legislation that would impose stricter regulation on oil and natural gas exploration and production activities in the state. For example, the legislature is currently considering a bill that would fundamentally alter Colorado’s approach to oil and natural gas exploration and production permitting, prioritizing environmental considerations over preventing the waste of mineral resources. Amongst other issues, the bill provides more authority to municipalities and county governments to impose their own siting and permitting requirements on operations and

 

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directs state agencies to adopt or consider new rules related to air emission monitoring and controls, asset integrity and plugging and abandonment obligations. This bill has the potential to significantly curtail new oil and gas development in Colorado.

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 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

 

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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 December 31, 2018, we had outstanding borrowings of $175 million under our term loan facility. The operating and financial restrictions and covenants in our term loan facility restrict, and any future financing 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 (ii) an asset coverage ratio of not less than 1.75 to 1.00, and (iii) a debt to capitalization ratio not to exceed 0.40 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;

 

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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

 

   

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

 

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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.

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

 

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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 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

 

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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 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

 

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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.

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

 

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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.”

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

 

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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 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. Furthermore, in connection with this offering, we will enter into a stockholders’ agreement with our Sponsors. The stockholders’ agreement provides each of our Sponsors with the right to designate a certain number of nominees to our board of directors so long as such Sponsor and its affiliates collectively beneficially own a specified percentage of the outstanding shares of our Class A and Class B common stock. In addition, the stockholders’ agreement provides our sponsors the right to approve certain material transactions so long as our Sponsors and their affiliates beneficially own specified percentages of our outstanding shares of Class A and Class B common stock. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” Finally, 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

 

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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

 

   

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

 

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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 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;

 

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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.

Furthermore, the terms of our amended and restated certificate of incorporation and amended and restated bylaws are subject to the terms of the stockholders’ agreement we will enter into with our Sponsors in connection with the offering. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

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 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, 2018 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

 

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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.”

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.

 

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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.

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.”

 

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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 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.

 

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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.

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.

 

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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.

 

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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.

 

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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 December 31, 2018, we had $175 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 December 31, 2018, the weighted average interest rate on borrowings under our term loan facility was 7.71%. 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.

 

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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.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2018:

 

   

on an actual basis for our predecessor; and

 

   

on an as adjusted basis to give effect to (i) the transactions described under “Corporate Reorganization,” (ii) 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 (iii) 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 December 31, 2018  
     Predecessor(1)      As Adjusted(2)  
     (In thousands, except number of
shares and par value)
 

Cash and cash equivalents

   $ 31,985      $                    
  

 

 

    

 

 

 

Long-term debt, including current maturities:

     

Term loan facility(3)

     175,000     
  

 

 

    

 

 

 

Total long-term debt

   $ 175,000      $    
  

 

 

    

 

 

 

Equity:

     

Members’ contributed capital

     208,728     

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

     168,824     
  

 

 

    

 

 

 

Total equity

   $ 377,552      $    
  

 

 

    

 

 

 

Noncontrolling interest

     

Total capitalization

   $ 552,552      $    
  

 

 

    

 

 

 

 

(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, Brigham Resources.

(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.

(3)

Excludes loan closing costs of $4.6 million. See Note 7 “Long-Term Debt” to our condensed consolidated financial statements included elsewhere in this prospectus.

 

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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 December 31, 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 December 31, 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 December 31, 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 December 31, 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   $    
  

 

 

    

 

 

   

 

 

    

 

 

   

 

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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.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

Brigham Minerals was formed in June 2018 and has limited 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, and selected pro forma financial data of Brigham Minerals. The selected historical consolidated financial data of our predecessor as of and for the years ended December 31, 2017 and 2018 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited pro forma statement of operations and balance sheet data as of and for the year ended December 31, 2018 has been prepared to give pro forma effect to (i) the reorganization transactions described under “—Corporate Reorganization” and (ii) this offering and the application of the net proceeds therefrom as if each had been completed on January 1, 2018, in the case of the statement of operations data, and on December 31, 2018, in the case of the balance sheet data. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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 historical financial statements of Brigham Resources and the pro forma financial statements of Brigham Minerals included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

     Brigham Minerals
Predecessor Historical
    Brigham Minerals
Pro Forma
 
     Year Ended
December 31, 
    Year Ended
December 31,
 
     2018     2017     2018  
                 (unaudited)  
    

(In thousands, except per share data)

 

Statement of Operations Data:

      

Revenue:

      

Mineral and royalty revenue

   $ 59,758     $ 30,066     $                    

Lease bonus and other revenue

     7,506       10,842    
  

 

 

   

 

 

   

 

 

 

Total revenue

     67,264       40,908    
  

 

 

   

 

 

   

 

 

 

Other operating income:

      

Gain on sale of oil and gas properties, net

     —         94,551    
  

 

 

   

 

 

   

 

 

 

Operating expense:

      

Gathering, transportation and marketing

     3,944       1,754    

Severance and ad valorem taxes

     3,536       1,601    

Depreciation, depletion and amortization

     13,915       6,955    

General and administrative

     6,638       3,935    
  

 

 

   

 

 

   

 

 

 

Total operating expense

     28,033       14,245    
  

 

 

   

 

 

   

 

 

 

Operating income

     39,231       121,214    
  

 

 

   

 

 

   

 

 

 

Other income (expense):

      

Gain/(Loss) on derivative instruments, net

     424       (121  

Interest expense, net

     (7,446     (556  

Gain (loss) on sale and distribution of equity securities

     823       (4,222  

Other income, net

     110       305    
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     33,142       116,620    
  

 

 

   

 

 

   

 

 

 

Income tax (benefit)/expense

     (220     1,008    
  

 

 

   

 

 

   

 

 

 

 

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     Brigham Minerals
Predecessor Historical
     Brigham Minerals
Pro Forma
 
     Year Ended
December 31, 
     Year Ended
December 31,
 
     2018      2017      2018  
                   (unaudited)  
    

(In thousands, except per share data)

 

Net income

   $ 33,362      $ 115,612      $                
  

 

 

    

 

 

    

 

 

 

Non-controlling interest

        

Net income attributable to common stockholders

        

Net income per share attributable to common stockholders

        

Basic

        

Diluted

        

Weighted-average number of shares

        

Basic

        

Diluted

        

Other Financial Data:

        

Adjusted EBITDA(1)

   $ 53,146      $ 33,618      $    

Adjusted EBITDA ex lease bonus(1)

     45,640        22,776     

Balance Sheet Data:

        

Cash and cash equivalents

   $ 31,985      $ 6,886      $    

Total assets

     554,026        334,477     

Long-term debt, including current maturities

     170,705        27,000     

Total liabilities

     176,474        32,303     

Total equity

     377,552        302,174     

 

(1)

Please read “Summary—Summary Historical and Pro Forma 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.

 

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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 and Pro Forma 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 11,648 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 December 31, 2018, we owned approximately 68,800 net royalty acres across 38 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 approximately 68,800 net royalty acres at December 31, 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 48% compound annual growth rate, or CAGR, from the beginning of 2013 through December 31, 2018, despite crude oil prices decreasing substantially during that same time period. As of December 31, 2018, we received royalty revenue from 3,355 gross horizontal wells and believe we will see continued growth in production, revenue and free cash flow from 806 DUCs, an average of 43 horizontal rigs running on our interests over the last year and 685 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

 

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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 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 $25.8 million, of which $22.0 million and $3.8 million closed in the third and fourth quarters of 2018, respectively. The allocation of the purchase price was $18.4 million to evaluated properties and $7.4 million to unevaluated properties.

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 $107.95 per barrel in June 2014. 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 $6.24 per MMBtu in January 2018. As of December 31, 2018, the posted price for oil was $45.15 per barrel and the Henry Hub spot market price of natural gas was $3.25 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

     82        968        8     153        2,037        8

Midland

     16        1,352        1     57        2,147        3

SCOOP

     24        111        22     51        269        19

STACK

     44        390        11     56        592        9

DJ

     147        759        19     229        1,359        17

Williston

     91        539        17     199        716        28

 

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     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
 

Other

     5        8        63     3        11        27
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total

     409        4,127        10 %      748        7,131        10 % 

Total wells turned to production on our acreage for the year ended December 31, 2017 increased by 94% 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

     71        925        8     109        1,658        7

Midland

     14        1,193        1     32        1,845        2

SCOOP

     41        124        33     39        210        19

STACK

     31        337        9     42        608        7

DJ

     80        733        11     210        1,297        16

Williston

     62        750        8     159        1,104        14

Other

     12        13        92     6        31        19
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total

     311        4,075        8     597        6,753        9

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.

 

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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.

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.

 

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For the year ended December 31, 2018, our gain on our commodity derivative instruments, net was $0.4 million. For the year ended December 31, 2017, our loss on commodity derivative instruments, net was $0.1 million. Our open oil and natural gas derivative contracts as of December 31, 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 December 31, 2018, we had in place crude oil swaps through December 2019 covering 1% of our projected crude oil 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 crude oil production from proved reserves. We had no natural gas derivative contracts in place as of December 31, 2018 and 2017.

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 and Pro Forma 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:

 

     Year Ended December 31,  
     2018     2017  

Revenue

    

Mineral and royalty revenues

    

Oil sales

     70     54

Natural gas sales

     11     13

NGL sales

     8     6
  

 

 

   

 

 

 

Total mineral and royalty revenue

     89     73
  

 

 

   

 

 

 

 

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     Year Ended December 31,  
     2018     2017  

Lease bonus revenue

     11     27
  

 

 

   

 

 

 

Total revenue

     100     100
  

 

 

   

 

 

 

Principle Components of Our Cost Structure

The following is a description of the principle components of our cost structure. However, as an owner of mineral and royalty interests, we are not obligated to fund drilling and completion capital expenditures to bring a horizontal well on line, lease operating expenses to produce our oil, natural gas and NGLs 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.

 

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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.

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

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

The following table provides the components of our predecessor’s revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:

 

     Year Ended December 31,               
           2018                  2017                Variance      
     (dollars in thousands, except for realized prices)  

Production

          

Oil (MBbls)

     777        454        323       70.9

Natural gas (MMcf)

     2,507        1,768        739       41.8

NGLs (MBbls)

     222        109        113       103.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents (MBoe)

     1,417        858        559       65.0

Equivalents per day (Boe/d)

     3,881        2,352        1,529       65.0

Revenues

          

Oil sales

   $ 47,040      $ 22,092      $ 24,948       112.9

Natural gas sales

     7,014        5,492        1,522       27.7

NGL sales

     5,704        2,482        3,222       129.8
  

 

 

    

 

 

    

 

 

   

 

 

 

Total mineral and royalty revenue

     59,758        30,066        29,692       98.8

Lease bonus and other revenue

     7,506        10,842        (3,336     (30.8 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenue

   $ 67,264      $ 40,908      $ 26,356       64.4

Other operating income:

          

Gain (loss) on sale of oil and gas properties, net

     —          94,551        (94,551     * ** 
  

 

 

    

 

 

    

 

 

   

 

 

 

Realized prices, without derivatives:

          

Oil ($/Bbl)

   $ 60.56      $ 48.61      $ 11.95       24.6

Natural gas ($/Mcf)

     2.80        3.11        (0.31     (10.0 )% 

NGLs ($/Bbl)

     25.72        22.71        3.01       13.3
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents ($/Boe)

   $ 42.19      $ 35.02      $ 7.17       20.5

Realized prices, with derivatives(1):

          

Oil ($/Bbl)

   $ 59.59      $ 48.61      $ 10.98       22.6

Equivalents ($/Boe)

     41.66        35.02        6.64       19.0

Operating expenses

          

Gathering, transportation and marketing

   $ 3,944      $ 1,754      $ 2,190       124.9

Severance and ad valorem taxes

     3,536        1,601        1,935       120.8

Depreciation, depletion, and amortization

     13,915        6,955        6,960       100.1

 

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     Year Ended December 31,              
           2018                 2017               Variance      
     (dollars in thousands, except for realized prices)  

General and administrative

     6,638       3,935       2,703       68.7
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

   $ 28,033     $ 14,245     $ 13,788       96.8

Other income (expense)

        

Gain (loss) on derivative instruments, net

   $ 424     $ (121   $ 545       (449.6 )% 

Interest expense, net

     (7,446     (556     (6,890     1,238.9
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense), net

   $ (7,022   $ (677   $ (6,345     937.2

 

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 twelve months ended December 31, 2018 increased by 64%, or $26.4 million, compared to the year ended December 31, 2017. The increase was attributable to a $29.7 million increase in mineral and royalty revenue during the period, partially offset by a $3.3 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 65% increase in production volumes to 3,881 Boe/d and a corresponding increase in revenue of $19.5 million. Realized commodity prices increased 20% resulting in an additional $10.2 million increase in mineral and royalty revenue.

Oil revenue for the year ended December 31, 2018 increased by 113%, or $24.9 million, compared to the year ended December 31, 2017. Oil production volumes increased 71% to 2,128 Boe/d resulting in a $15.7 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 25% to $60.56 per barrel, resulting in an additional increase in revenue of $9.2 million.

Natural gas revenue for the year ended December 31, 2018 increased by 28%, or $1.5 million, compared to the year ended December 31, 2017. Natural gas production volumes increased 42% to 6,869 Mcf/d resulting in a $2.3 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, North Dakota and Oklahoma. Realized natural gas prices decreased by 10% to $2.80 per Mcf resulting in an offsetting decrease in revenue of $0.8 million.

NGL revenue for the year ended December 31, 2018 increased by 130%, or $3.2 million compared to the year ended December 31, 2017. NGL production volumes increased by 103% to 608 Boe/d, resulting in a $2.5 million increase in NGL sales, while realized NGL prices increased by 13% to $25.72 per barrel, resulting in an additional increase in revenue of $0.7 million.

Lease bonus revenue for the year ended December 31, 2018 decreased by 31%, or $3.3 million, compared to the year ended December 31, 2017. The decrease was primarily attributable to a decrease in 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

 

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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, 2018 increased by 125%, or $2.2 million, as compared to the year ended December 31, 2017, which was largely driven by the 65% increase in our production volumes.

Severance and ad valorem taxes for the year ended December 31, 2018 increased by 121%, or $1.9 million, as compared to the year ended December 31, 2017, which was 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 for the year ended December 31, 2018 increased by 100%, or $7.0 million, compared to the year ended December 31, 2017, which was primarily due to an increase in depletion expense of $7.1 million. Higher production volumes increased our depletion expense by $4.1 million, and a higher depletion rate increased our depletion expense by $3.0 million.

General and administrative expense for the year ended December 31, 2018 increased by 69%, or $2.7 million, compared to the year ended December 31, 2017 as a result of increased headcount and incremental business development expenses.

Interest expense for the year ended December 31, 2018 increased $6.9 million compared to the year ended December 31, 2017 due to greater average outstanding borrowings and higher interest rates under our term loan facility. The need for greater borrowings was driven by our increased acquisition pace in 2018 relative to 2017.

For the year ended December 31, 2018, we recognized a gain on derivative instruments, net of $0.4 million, which is attributable to oil derivative instruments. We realized $0.8 million of losses on our settled derivative instruments during the year ended December 31, 2018. 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.

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.

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

 

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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 margin 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 would be subject to a blended statutory rate of 22.9% of 2018 pre-tax earnings. Based on blended statutory rates of 36.5% and 22.9% for 2017 and 2018, respectively, Brigham Minerals would have incurred pro forma income tax expense for the years ended December 31, 2017 and 2018 of approximately $42.6 million and $7.6 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 or any other credit 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 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 year ended December 31, 2018 and 2017, we incurred approximately $195.6 million and $101.4 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 year ended December 31, 2019, 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,

 

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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 December 31, 2018, we had $175.0 million outstanding under our term loan facility with $25.0 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 $53.6 million and $20.1 million as of December 31, 2018 and 2017, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. For the year ended December 31, 2018, we recorded an allowance for doubtful accounts in the amount of $0.4 million, which is included in general and administrative expenses.

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 $32.0 million and $6.9 million at December 31, 2018 and 2017, respectively. We expect that our cash flows from operations and availability under our term loan facility or any other credit 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:

 

     Year Ended
December 31,
 
     2018     2017  
     (In thousands)  

Net cash provided by operating activities

   $ 31,444     $ 29,401  

Net cash provided by/(used in) investing activities

     (195,742     26,172  

Net cash (used in)/provided by financing activities

     189,397       (82,647

Analysis of Cash Flow Changes Between the Year Ended December 31, 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 65% increase in production volumes and the 20% increase in realized prices during the year ended December 31, 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 year ended December 31, 2018, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $195.6 million and additions to other fixed assets of $0.7 million. Our cash flows from investing activities for the year ended December 31, 2018 also reflects $0.9 million of proceeds from the sale of equity securities and a transfer of $0.4 million of these proceeds to restricted cash to be distributed to investors.

 

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For the year ended December 31, 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 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.

Financing activities. Net cash provided by financing activities for the year ended December 31, 2018 included $46.0 million in net capital contributions from the Existing Owners and $213.4 million in additional borrowings under our prior revolving credit facility and new term loan facility combined, net of $4.6 million in associated loan closing costs. This was partially offset by payment of $70.0 million to pay off and terminate the prior revolving credit facility on July 28, 2018 using funds from the new term loan facility.

Net cash used in financing activities for the year ended December 31, 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.

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.

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 December 31, 2018, we had $175.0 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.

 

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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 December 31, 2018 is provided in the following table:

 

     2019      2020      2021      2022      2023      2024 and
Thereafter
     Total  
     (In thousands)  

Long-term debt obligations(1)

   $ 2,187      $ 8,480      $ 8,064      $ 7,668      $ 7,292      $ 141,309      $ 175,000  

Office lease

     538        654        672        689        474        111        3,138  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,725      $ 9,134      $ 8,736      $ 8,357      $ 7,766      $ 141,420      $ 178,138  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

As of December 31, 2018, we had $175 million outstanding under our term loan facility and $25 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.”

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 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 $107.95 per barrel in June 2014, and as of December 31, 2018, the posted price for oil was $45.15 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 $6.24 per MMBtu in January 2018, and as of December 31, 2018, the Henry Hub spot market price of natural gas was $3.25 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.”

 

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A $1.00 per barrel change in our realized oil price would have resulted in a $0.8 million change in our oil revenues for the year ended December 31, 2018. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million change in our natural gas revenues for the year ended December 31, 2018. A $1.00 per barrel change in NGL prices would have resulted in a $0.2 million change in our NGL revenues for the year ended December 31, 2018. Royalties on oil sales contributed 70% of our total revenues for the year ended December 31, 2018. Royalties on natural gas sales contributed 11% and royalties on NGL sales contributed 8% of our total revenues for the year ended December 31, 2018.

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

Our open positions as of December 31, 2018 are as follows:

 

Description & Production Period

   Volume      Weighted
Average Swap
Price
 
     (Bbl)      ($/Bbl)  

Crude Oil Swaps:

     

January 2019 — March 2019(1)

     20,000      $ 64.60  

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

     65,000      $ 63.91  

 

(1)

Includes swaps for 5,000 Bbl valued as an asset of $0.1 million that matured on December 31, 2018 and will be settled in January 2019.

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

As of December 31, 2018, we had $175.0 million of debt outstanding under our term loan facility, with an assumed weighted average interest rate of 7.71%. 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

 

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(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 $1.8 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.

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, 2018 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. Receivables from new wells turned in line for which we did not receive payment at the time revenues are recognized are estimated and recognized only when public production information is available. 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.

 

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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 recorded an allowance for doubtful accounts for $0.4 million for the year ended December 31, 2018, which is included in general and administrative expenses. We did not record any allowance for doubtful accounts for the year ended December 31, 2017.

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.

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 2018 and 2017.

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 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

 

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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, 2018 and 2017, the full cost ceiling value of our reserves was calculated based on the average posted first-day-of-the month prices for the 12 months ended December 31, 2018 and 2017, in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price was adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 22% to 41% and from 19% to 42% of the oil posted price during the twelve months ended December 31, 2018 and 2017, respectively. For gas volumes, the average Henry Hub spot price 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, held constant over the remaining lives of the properties, are $61.31 and $47.80 per barrel of oil, $23.98 and $18.56 per barrel of NGL and $2.51 and $2.74 per Mcf of gas as of December 31, 2018 and 2017, respectively. Using these prices, the net book value of oil and natural gas was below the ceiling limitation and no write-off was necessary.

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. Receivables from new wells turned in line for which we did not receive payment at the time revenues are recognized are estimated and recognized only when public production information is available. 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.

 

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Recently Issued Accounting Pronouncements

See “Note 2—Significant Accounting Policies—Recently Issued Accounting Standards” to our consolidated financial statements as of December 31, 2018 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, 2019. 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.

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 year ended December 31, 2017 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

 

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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 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. Due to the material weaknesses described above, management performed additional analyses and procedures in order to conclude that our consolidated financial statements for the year ended December 31, 2018 are fairly presented, in all material respects, in accordance with generally accepted accounting principles. 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, 2018 and 2017. 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.

 

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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 11,648 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 38 of the most highly active counties for horizontal drilling in the continental United States. According to RSEG, an affiliate of Warburg Pincus, as of December 31, 2018, operators have deployed 60% of the horizontal rig fleet, and 68% of the liquids-focused horizontal rig fleet, in the continental United States in these same 38 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 approximately 68,800 net royalty acres at December 31, 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 48% compound annual growth rate from the beginning of 2013 through December 31, 2018, despite crude oil prices decreasing substantially during that same time period, as illustrated by the following chart.

 

 

LOGO

 

Since inception, we have executed on our technically driven, disciplined acquisition approach and have closed 1,292 transactions with third-party mineral and royalty interest owners as of December 31, 2018. We have increased our mineral and royalty interests from approximately 10,200 net royalty acres as of December 31,

 

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2013, to approximately 68,800 net royalty acres as of December 31, 2018, which represents a 47% 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.

 

     2012      2013      2014      2015      2016      2017      2018      Total  

Net Royalty Acres (NRAs) Acquired

     500        9,700        17,300        7,200        9,800        9,400        14,900        68,800  

Number of Acquisitions

     15        313        380        152        121        110        201        1,292  

Average NRAs per Acquisition

     33        31        46        47        81        85        74        53  

NRAs at Period End

     500        10,200        27,500        34,700        44,500        53,900        68,800        68,800  

By targeting core, top-tier mineral acreage, our interests have continued to see rapid development with a total of approximately 748 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 65% from 2017 to 2018. Further, our production volumes are comprised of high-value liquids with 70% of our volumes for the twelve months ended December 31, 2018 composed of crude oil and NGLs, which represents 88% 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 99% increase in our royalty revenue from 2017 to 2018. We expect to see future organic growth in our production, revenue and free cash flow from 806 DUCs across our interests and approximately 685 horizontal drilling permits as of December 31, 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 December 31, 2018, there have been an average of 43 horizontal rigs across our acreage, developing an average 1,600 net mineral acres, which we believe provides visibility toward future production growth.

 

Average Quarterly Rigs on Acreage   Average Quarterly NMA Under Development
LOGO   LOGO

 

In addition to existing near-term development, our permitted horizontal drilling locations represent only approximately 6% of the remaining proved, probable and possible undeveloped horizontal drilling locations incorporated by CG&A in our reserve report as of December 31, 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, our Executive Chairman, Ben (Bud) Brigham, 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. Brigham Exploration utilized its technical capabilities in the Williston Basin to identify and acquire highly prospective leasehold acreage with favorable

 

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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.

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 December 31, 2018, our mineral and royalty interests consisted of approximately 48,100 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 17.9%. Typically, within the minerals industry, mineral owners standardize ownership to a 12.5%, or 1/8th, royalty interest, which is referred to as a “net royalty acre.” Our net mineral acres standardized to a 1/8th royalty equate to approximately 68,800 net royalty acres. When standardized on a 100% royalty basis, these approximately 68,800 net royalty acres equate to approximately 8,600 “100% royalty acres.” Our approximately 68,800 net royalty acres are located within 1,367 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 approximately 1,356,000 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 December 31, 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)

48,100

   17.9%   

68,800

  

8,600

  

1,356,000

   0.6%

 

(1)

Standardized to a 1/8th royalty (i.e., 48,100 net mineral acres * 17.9% / 12.5%).

(2)

Standardized to a 100% royalty (i.e., 68,800 net royalty acres * 12.5%).

(3)

Calculated as number of 100% royalty acres per gross DSU acre (i.e., 8,600 100% royalty acres / 1,356,000 gross DSU acres).

In addition to mineral interests, which represented approximately 97% of our net royalty acres as of December 31, 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

 

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category because they share many of the same characteristics due to the nature of the underlying interest. As of December 31, 2018, we owned approximately 1,700 net royalty acres of NPRIs.

 

   

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 December 31, 2018, we owned approximately 400 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 December 31, 2018.

LOGO

 

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In addition, the following table summarizes certain information regarding our primary focus areas. Our average daily net production for the three months ended December 31, 2018 was comprised 55% of oil production, 28% of natural gas production and 17% of NGL production.

 

Basin

   Acreage as of December 31, 2018     Gross
Horizontal
Producing
Well
Count as of
December 31,
2018(4)
     Average Daily Net
Production for
Three Months
Ended
December 31,
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

     11,600        20.7     19,200        2,400        229,000        1.0     469        1,982  

Midland

     2,600        15.4     3,200        400        58,000        0.7     104        197  

SCOOP

     5,900        18.4     8,700        1,090        167,000        0.7     262        467  

STACK

     6,800        17.8     9,700        1,210        156,000        0.8     211        563  

DJ

     12,100        15.9     15,400        1,920        165,000        1.2     838        817  

Williston

    
5,200
 
     16.3     6,800        850        470,000        0.2     1,379        436  

Other

     3,900        18.6     5,800        730        111,000        0.7     92        118  
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     48,100        17.9     68,800        8,600        1,356,000        0.6     3,355        4,579  
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

Note:

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

(1)

Standardized to a 1/8th 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 December 31, 2018, according to RSEG, there were approximately 236 and 165 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 December 31, 2018, according to RSEG, there were approximately 32 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

 

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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 December 31, 2018, according to RSEG, there were approximately 70 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 December 31, 2018, according to RSEG, there were approximately 30 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 December 31, 2018, according to RSEG, there were approximately 54 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.”