q4 2019 investor presentation · q4 2019 summary statistics ~125 total operators operator exposure...

Q4 2019 Investor PresentationFebruary 2020

MNRL

DisclaimerThe financial projections and other estimates contained herein are forward-looking statements with respect to the anticipated performance of Brigham Minerals, Inc. and its affiliates (collectively, “Brigham,” the “Company” or

“MNRL”). Such financial projections and estimates are as to future events and are not to be viewed as facts, and reflect various assumptions of management of the Company concerning the future performance of the Company

and are subject to significant business, financial, economic, operating, competitive and other risks and uncertainties and contingencies (many of which are difficult to predict and beyond the control of the Company) that could

cause actual results to differ materially from the statements included herein. In addition, such financial projections and estimates were not prepared with a view to public disclosure or compliance with published guidelines of the

Securities and Exchange Commission (the “SEC”), the guidelines established by the American Institute of Certified Public Accountants or U.S. generally accepted accounting principles (“GAAP”). Accordingly, although the

Company’s management believes the financial projections and estimates contained herein represent a reasonable estimate of the Company’s projected financial condition and results of operations based on assumptions that

the Company’s management believes to be reasonable at the time such estimates are made and at the time the related financial projections and estimates are delivered, there can be no assurance as to the reliability or

correctness of such financial projections and estimates, nor should any assurances be inferred, and actual results may vary materially from those projected. Additionally, this presentation also includes other forward-looking

statements. All statements, other than statements of historical fact included in this presentation regarding Brigham’s 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 presentation, the words “could”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” 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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary

statements that are disclosed from time to time in the Company’s filings with the SEC, including those described under the heading “Risk Factors” included in the Company’s Quarterly Reports on Form 10-Q and Annual

Reports on Form 10-K. These include, but are not limited to, downturns in operator activity due to commodity price fluctuations, the Company’s ability to integrate acquisitions into its existing business, changes in oil, natural

gas and NGL prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, operational factors affecting the commencement or maintenance of producing wells on the

Company’s properties, the condition of the capital markets generally, as well as the Company’s ability to access them, global or national health concerns, including the outbreak of pandemic or contagious disease, the proximity

to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors. Except as

otherwise required by applicable law, Brigham disclaims 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 presentation. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and

operating results of the Company, including the Company’s minerals acquisition capital budget and other guidance including 2020 production guidance within this presentation.

The Company uses Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA margin and discretionary cash flow financial measures that are not presented in accordance with GAAP.

Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA margin and discretionary cash flow are supplemental non-GAAP financial measures that are used by the Company’s management

and external users of the Company’s financial statements such as investors, research analysts and others to assess the financial performance of the Company’s assets and their ability to sustain dividends over the long term

without regard to financing methods, capital structure or historical cost basis.

The Company defines Adjusted net income as net income (loss) before loss on extinguishment of debt. The Company defines 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. The Company defines

Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus revenue the Company receives due to the unpredictability of timing and magnitude of the revenue. The Company

defines Adjusted EBITDA margin as Adjusted EBITDA divided by total revenue. The Company defines discretionary cash flow as Adjusted EBITDA less cash interest expense and cash taxes.

Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA margin and discretionary cash flow do not represent and should not be considered alternatives to, or more meaningful than, net

income (loss), income from operations, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of the Company’s financial performance. Adjusted

net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA margin and discretionary cash flow have important limitations as analytical tools because they exclude some but not all items that affect net

income (loss), the most directly comparable GAAP financial measure. The Company’s computation of Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA margin and discretionary cash

flow may differ from computations of similarly titled measures of other companies. Please see Appendix for a reconciliation of Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus, Adjusted EBITDA

margin and discretionary cash flow to net income (loss), the Company’s most directly comparable financial measure calculated in accordance with GAAP.

This presentation has been prepared by the Company and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published

independent sources. Although the Company believes these third-party sources are reliable as of their respective dates, the Company has not independently verified the accuracy or completeness of this information. Some

data are also based on the Company’s good faith estimates, which are derived from its review of internal sources as well as the third-party sources described above.

The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose estimated proved reserves, which are estimates of reserve quantities that geological and engineering data demonstrate with

reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms.

Additional information regarding the Company's estimated reserves is contained in other documents filed by the Company with the SEC. Actual quantities of oil, natural gas and natural gas liquids that may be ultimately

recovered may differ substantially from estimates. Factors affecting ultimate recovery include the scope of the operators' ongoing drilling programs, which will be directly affected by the availability of capital, drilling and

production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical

factors affecting recovery rates. Estimates of potential resources may also change significantly as the development of the properties underlying the Company's mineral interests provides additional data. This presentation also

contains the Company's internal estimates of its potential drilling locations, which may prove to be incorrect in a number of material ways. The actual number of locations that may be drilled may differ substantially from

estimates.

Neither the Company nor any of its affiliates, representatives or advisors assumes any responsibility for, and makes no representation or warranty (express or implied) as to, the reasonableness, completeness, accuracy or

reliability of the financial projections, estimates and other information contained herein, which speak only as of the date identified on cover page of this presentation. The Company and its affiliates, representatives and advisors

expressly disclaim any and all liability based, in whole or in part, on such information, errors therein or omissions therefrom. Neither the Company nor any of its affiliates, representatives or advisors intends to update or

otherwise revise the financial projections, estimates and other information contained herein to reflect circumstances existing after the date identified on the cover page of this presentation to reflect the occurrence of future

events even if any or all of the assumptions, judgments and estimates on which the information contained herein is based are shown to be in error, except as required by law.

MNRL

Brigham Minerals OverviewUtilize Operator Experience and Technical Evaluation to Acquire in the Core

Founders

Acquired ~82,200 net royalty acres across four

liquids-rich basins(1)

Multifaceted Technical Analysis

Strong Sourcing Engine in Targeted Areas

Strong Free Cash Flow

High Margin / No LOE

Total Return with

Growing Dividend

Organic Growth with No

Capex

Identify Core Geology in Liquids-Rich Resource Plays Under Top-Tier Operators

Return Oriented ValuationMinerals –

The Advantaged

Asset Class

Delaware, Midland,

SCOOP/STACK,

DJ, & WillistonPortfolio Areas

Sophisticated and Technically Disciplined

Evaluation Model Leveraging E&P Experience to

Acquire Minerals

(1) As of December 31, 2019.

(2) As of February 27, 2020 redetermination.

Business Plan

Market Snapshot (1)

NYSE Ticker: MNRL

Market Cap: $1.2 billion

Share Count: 56.89 million

Debt: $0 million

12/31 Liquidity: $201 million

RBL Capacity: $180 million(2)

Structure: C-corp

Bud Brigham

Rob Roosa

MNRL

2006

Begin Building Williston Acreage Position

2007

Add Acreage and Begin Drilling Wells

2008Begin Acquiring Minerals

2009Monetize Minerals for 2X return to fund

drilling and midstream

2016 / 2017Sale to FANG for $2.55bn

Brigham Track RecordConsistent History of Shareholder Value Creation in Resource Plays

2010

Add Acreage and Drill Wells

Brigham Exploration

2013

Enter Southern Delaware Basin

2014Delineate Southern Delaware Position

2015Larger Completions Create Step Change in

Value

Brigham Resources

2016Continued Completion Enhancements

Brigham Minerals

2012Enter Anadarko (SCOOP)

2013Enter DJ and Williston

2014Enter Permian Basin

2016 / 2017Sold 5,745 Net Mineral Acres to FANG

2017Increased Net Mineral Position by 21% YoY

2011Sale to Statoil for $4.4bn

2018Increased Net Mineral Position by 28% YoY

2019IPO / Follow On

Increased Mineral Position By 19%

Increased Production By 91%

Increased EBITDA ex Lease Bonus (1)

By 63%

(1) See Appendix to this presentation for GAAP to non-GAAP reconciliations.

MNRL

OXY12%

NBL6%

OVV6%

CLR5%

MRO4%

XOM4%

XEC4%DVN

4%

EOG3%

FANG3%

PRI3%

PXD3%

CPE3%

PDCE3%

WLL3%

RDS2%

XOG2%

CVX2%

PE2%

CXO2%

Other Public8%

Other Private16%

Q4 2019 Summary Statistics

~125 total

operators

Operator Exposure by NRI (3)

Brigham Minerals IntroductionTargeted Acquisitions in the Core of Liquids Rich Resource Plays

Net Mineral Acres 57,800 (18% RI)

Net Royalty Acres 82,200 (12.5% RI)

Net Production 9,627 Boe/d

Adjusted EBITDA (2) $26.8 M

Gross / Net Hz Producing well count 4,908 / 29

Gross / Net Hz Undeveloped well count 12,777 / 112

Gross Avg. Hz Rigs / NRA Under Development 60 / 2,467

Gross / Net DUCs 892 / 5.9

Gross / Net Active Permits 715 / 4.4

Brigham Minerals Position By County Net Royalty Acres by Area (1)

73%

Liquids

Source: Company data, YE 2019 Internal Reserves, Drilling Info, IHS. Data as of 12/31/2019.

(1) Other includes Extended Woodford, Merge and Marcellus.

(2) See Appendix to this presentation for GAAP to Non-GAAP reconciliations.

(3) NRI per location normalized to 7,500’ lateral.

Q4 2019 Net Production (9,627 Boe/d)Delaware Midland

SCOOP/STACK

Williston

DJ

Delaware, 25,750 , 31%

Midland, 4,100 , 5%

Scoop, 11,100 , 14%

Stack, 10,700 , 13%

DJ, 15,600 , 19%

Williston, 7,750 , 9%

Other, 7,200 , 9%

82,200 NRA

Oil58%

Gas27%

NGL15%

MNRL

2,352

3,881

7,414

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2017 2018 2019102

84 80

73

22 25 21 18

0

30

60

90

120

1Q19 2Q19 3Q19 4Q19

MNRL Rig Density Per 100K NRA Peer Average Rig Density

Production & RevenueDUC Inventory Provides Visibility to Continued Growth

Boe/d Prior Period Gross DUCs

Net Production and DUC Inventory Average Quarterly Rigs and NRA Under Development

Source: Company filings and Drilling Info.

Note: DUC inventory from the audited YE 2019 reserve report.

Peers Include: BSM, FLMN, KRP and VNOM

YE17

DUCs

497

YE18

DUCs

808

PDP, Q4 2019 DUC inventory and

current rig activity provides

visible foundation for strong 2020 / 2021

Growth

YE19

DUCs

892

2018

Converted

88%

DUC Conversion

25

31

51

64

73

62 63 60

0

1,000

2,000

3,000

4,000

0

20

40

60

80

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

Delaware Midland SCOOP

STACK DJ Basin Williston

Other NRA Under Dev

Rigs NRA

4.1x

Greater

Than Peers

46 Rigs in Jan.,

~3,000 NRA

Under Dev.2019

Converted

86%

MNRL

Acquired31%

DUCs68%

Other1%

4.5 4.4

3Q19 4Q19

6.2 5.9

3Q19 4Q19

4,359 4,908

376 168 5

0

1,000

2,000

3,000

4,000

5,000

6,000

3Q19 DUCs Acquired Other 4Q19

Location Conversion and ReloadingOrganic Development & Acquisitions Underpin DUC and Permit Maintenance

Gross PDP Location Rollforward

Gross DUC Location Rollforward

549 Wells

Added

to PDP in Q4

2019

Net DUCs Net Permits

Reloaded DUC inventory despite ~40% DUC conversions during Q4 2019

996892

(376)

9491

87

0

200

400

600

800

1,000

1,200

3Q19 DUCs PDP Permit Unpermitted Acquired 4Q19 DUCs Acquired38%

DUCs45%

Permits9%

Unpermitted8%

1,553 Wells

Added

to PDP in

2019

MNRL

19%

DUCs &

Permits

PDP21%

DUCs14%

Permits5%

Unpermitted60%

8%

DUCs &

Permits

PDP18%

DUCs5%

Permits3%

Unpermitted74%

2019 Acquisition SummaryQ4 2019 Acquisition Capital Allocation into Less Competitive, Highest Value Areas

7%

DUCs &

Permits

59% 60%72%

45%

3% 11%6%

11%

0%

20%

40%

60%

80%

100%

1Q2019 2Q2019 3Q2019 4Q2019

Delaware Midland SCOOP STACK DJ Williston Other

1H2019 Acquisitions $7.6 mm / 8%

3Q2019 Acquisitions $11.0 mm / 24%

$-

$4

$8

$12

$16

0% 10% 20% 30% 40% 50%

Diversified Acquisitions Generated Superior $ / Net Well with Near Term Activity

Q4 2019 Acquisition Net Well by Type% of Net Wells by Type at end of Q3 2019 % of Net Wells by Type at end of Q4 2019

Net Well Acquisitions by Basin by Quarter $mm per Net Well vs % Net DUCs and Permits

$mm / Net Well

Net DUCs and Permits as a % of Total Net Wells

Pursuing Compelling Opportunities Across Basins % of Net DUCs and Permits Drives $ / Net Well

1H2019 Acquisitions $7.6 mm / 8%



$-

$4

$8

$12

$16

0% 10% 20% 30% 40% 50%

PDP20%

DUCs4%

Permits3%

Unpermitted73%

At of the end of Q3 2019 and

prior to conversions during Q4 2019

MNRL

2019 Mineral AcquisitionsSuccessful Execution of Targeted Acquisition Strategy

MNRL Acreage as of YE18

MNRL Acreage 2019 YTD

Active Rig

23% 19%13%

6%4% 2% 1% 1% 1%

20%

5% 4%

Loving Reeves Eddy Ward Upton Martin Howard Reagan Midland Grady McClain Garvin

Delaware Midland SCOOP

5,750 NRA 1,000 NRA 2,750 NRA

% of NRA Acquired YTD 2019 By County in Permian and SCOOP

Delaware Mineral Position Midland Mineral Position SCOOP Mineral Position

Grady

Stephens

McClain

MNRL

Oil60%

Gas22%

NGL18%

Oil57%

Gas37%

NGL6%

Delaware Basin Midland Basin SCOOP STACK DJ Basin Williston Basin Total (1)

NRA / % of Total 25,750 / 31% 4,100 / 5% 11,100 / 14% 10,700 / 13% 15,600 / 19% 7,750 / 9% 82,200 / 100%

Q4 2019 Prod. (Boe/d) / % of Total 4,630 / 48% 424 / 4% 1,128 / 12% 1,145 / 12% 1,292 / 13% 918 / 10% 9,627 / 100%

Production by Product (2)

Gross / Net DUCs 255 / 2.4 136 / 0.8 118 / 0.7 19 / 0.1 181 / 1.4 155 / 0.5 892 / 5.9

Gross / Net Permits 168 / 1.3 119 / 0.4 15 / 0.1 10 / 0.0 201 / 2.2 198 / 0.3 715 / 4.4

3P Wells per DSU (3)

Q4 2019 Avg Rigs Running (4) 20 12 16 0 3 7 60

Top Operators

Oil

69%

Gas

19%

NGL

12%

Oil58%

Gas27%

NGL15%

Oil56%

Gas32%

NGL12%

Oil76%

Gas15%

NGL9%

Oil37%

Gas41%

NGL22%

Note: Includes only Horizontal Locations.

(1) Includes Extended Woodford, Merge and Marcellus.

(2) Product mix displayed for Q4 2019.

(3) 3P wells per DSU from Q4 2019 Audited Reserve Report.

(4) In 4Q an average of 2 rigs drilled Merge acreage not included in the Mid-Con rig statistics above.

Portfolio Area OverviewCore Position in Premier Liquids-Rich Basins

14.53P/DSU

15.23P/DSU

9.13P/DSU

11.53P/DSU

15.23P/DSU

9.53P/DSU

11.73P/DSU

78%

Liquids

82%

Liquids

63%

Liquids

59%

Liquids

68%

Liquids

85%

Liquids

73%

Liquids

PD /

DSU., 3.7

Undev. /

DSU., 8.1

PD /

DSU., 5.1

Undev. /

DSU., 4.4

PD /

DSU., 6.8

Undev. /

DSU., 8.4

PD /

DSU., 2.2

Undev. /

DSU., 9.3

PD /

DSU., 3.1

Undev. /

DSU., 5.9

PD /

DSU., 3.6

Undev. /

DSU.,

11.6

PD /

DSU., 2.9

Undev. /

DSU.,

11.5

MNRL

Undeveloped Core Inventory Drives Capex Free Long-Term Organic Growth

Investment Thesis

Dedicated and Technically Focused Team with Strong Shareholder Alignment

Strong Free Cash Flow Generation

Strong Balance Sheet with Significant Consolidation Opportunities

Core Mineral Position Under High-Quality, Well-Capitalized Operators

DUCs Drive Visible 2020 Production Growth

MNRL

Portfolio Overview & Highlights

MNRL

PD /

DSU., 5.1

Undev. /

DSU., 4.4

PD /

DSU., 6.8

Undev. /

DSU., 8.4

PD /

DSU., 2.2

Undev. /

DSU., 9.3

9.13P/DSU

Undeveloped Gross LocationsTotal Gross Locations

Source: YE 2019 audited reserve report. Spacing data as of December 31, 2019.

(1) Other includes Extended Woodford, Merge and Marcellus.

(2) Inventory life calculated as 3P undeveloped locations divided by 1,104 gross wells spud in 2019.

(3) Includes PDP and internally classified DUCs, including 67 PUDs that have spud dates after the December 1, 2019 effective date.

12 Years of

Inventory

Life(2)

Substantial Organic Inventory67% of Gross & 74% of Net Undeveloped Locations in Permian/SCOOP/STACK

Williston Wells per DSU

Delaware Wells per DSU Midland Wells per DSU SCOOP Wells per DSU

Midland Wells per DSU STACK Wells per DSU

11.53P/DSU

15.23P/DSU

9.53P/DSU

PD / DSU Undev / DSU

STACK Wells per DSU DJ Wells per DSU

14.53P/DSU

15.23P/DSU

(1)

9%

12%

12%

14%

9%8%

36%

Undeveloped Locations

Delaware

Midland

SCOOP

STACK

DJ

Williston

Other5,800

12,777

18,577

Inventory

3P (69%)

PD (31%)

PD /

DSU., 3.1

Undev. /

DSU., 5.9

PD /

DSU., 3.6

Undev. /

DSU.,

11.6

PD /

DSU., 2.9

Undev. /

DSU.,

11.5

(3)

MNRL

1,112

840

699

405

1,159

989

763

784

308

118

360

292

294

440

151

469

645

1,070

1,879

Other

Three Forks

Bakken

Codell

Niobrara

Woodford

Meramec

Woodford

Springer

Other

Lower Spraberry

Wolfcamp B

Wolfcamp A

Other

Avalon

2nd Bone Spring

3rd BS / WC XY

Wolfcamp B

Wolfcamp A

6.9

1.7

1.3

5.1

14.8

8.6

6.9

6.1

2.3

0.9

2.5

2.0

2.1

5.5

0.7

3.8

5.7

12.6

22.3

Other

Three Forks

Bakken

Codell

Niobrara

Woodford

Meramec

Woodford

Springer

Other

Lower Spraberry

Wolfcamp B

Wolfcamp A

Other

Avalon

2nd Bone Spring

3rd BS / WC XY

Wolfcamp B

Wolfcamp A

100% Net Horizontal Well Locations – (111.8)Gross Horizontal Well Locations - (12,777)

52% of Net Locations in Permian and 35% of Net Locations are Wolfcamp

Source: MNRL YE 2019 audited reserve report.

Organic Undeveloped Inventory14 Year Organic Inventory to Drive Production and Cash Flow

8%

9%

12%

12%

36%

9%

14%

Delaware Midland SCOOP STACK DJ Williston Other Delaware Midland SCOOP STACK DJ Williston Other

7%

8%

18%

3%

45%

6%

14%

MNRL

Wolfcamp A44%

Wolfcamp B25%

3rd BS / WC XY11%

2nd Bone Spring

8%Avalon

1%

Other11%

Delaware31%

Midland5%Scoop

14%

Stack13%

DJ19%

Williston9%

Other9%

MNRL DSUs

Delaware Basin OverviewCore Outline Validated by Operator Rig Activity

Delaware

25,750

NRAs

Key Operators

Undeveloped Well Locations

Net Royalty Acres

50.6

Net Wells

MNRL Core Outline

4,654 gross wells12,777 gross wells

Loving County

Development Area

111.8

Net Wells

Delaware45%

Midland7%SCOOP

7%

STACK14%

DJ18%

Williston3%

Other6%

Source: Public Data, DrillingInfo and IHS.

Note: Asset data as of December 31, 2019.

MNRL DSU Acreage

Active Rig

MNRL

LCDA UpdateUnderpinned by Proven Operators and Superior Geology

Loving County Development Area OXY / XTO / EOG / SHELL

Operator RigsDUCs /

Permits

Active

Develop.

Zones

Activity in

McGregor D-5

Unit

9 Gross DUCs

/ 4 Gross

Permits

3rd Bone

Spring, Upper

WC & Avalon

2 Rigs on

MNRL

Position

17 Gross

DUCs / 4

Gross Permits

3rd Bone

Sand & Upper

WC

2 Rigs in

LCDA

10 Gross

DUCs / 0

Gross Permits

WC X/Y, WC

A & WC B

5 Rigs in

LCDA, 2 Rigs

on MNRL

14 Gross

DUCs / 5

Gross Permits

3rd Bone

Sand & Upper

WC

PDP, 86, 50%DUCs,

59, 35%

Permits, 26, 15%

LCDA Gross Wells & NRA Owned

MNRL Owns

Over 3,400

NRA in the

LCDA

As of February 23, 2020

MNRL

Financial Overview

MNRL

$8.2 $9.4

$8.4 $7.4

$4.2

($3.2)

$8.5

$12.3

$(10)

$(5)

$-

$5

$10

$15

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

76%82% 83%

74% 76% 74% 77%80%

0%

20%

40%

60%

80%

100%

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

Quarterly Financial Results

Total Revenue and Realized Price

Net Income

Adjusted EBITDA(1)

Adjusted EBITDA Margin(1)

$ in mm and $ / Boe $ in mm


(2) Adjusted Net Income of $3.7 million.

CAGR

58%

Rev.

CAGR

53%

Lease Bonus

Adjusted EBITDA Ex. Lease Bonus

(1)

$14.1 $16.9

$18.7 $17.6 $18.3

$24.5 $25.1

$33.1

$40.54$42.87

$45.26

$40.15

$36.31

$37.42$33.51

$37.39

$0.00

$7.00

$14.00

$21.00

$28.00

$35.00

$42.00

$49.00

$-

$5

$10

$15

$20

$25

$30

$35

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

$8.5

$11.4 $13.3 $12.4 $13.1

$16.8 $18.3

$26.3

$10.8

$13.8 $15.5

$13.0 $13.8

$18.3 $19.3

$26.8

$-

$5

$10

$15

$20

$25

$30

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

(2)

MNRL

$51

$150

$201

1Borrowing Capacity 12.31.2019

Cash 12.31.2019

10%

15%

25%

0%

100%

200%

300%

0%

10%

20%

30%

Annualized Return % of PSU Target Earned

Financial Policies

❑ No annual cash bonuses

❑ Share-based Compensation (LTIP):

▪ Executive Chairman 100% Performance-Based Restricted Stock Units (“PSUs”)

▪ Management team 50% Restricted Stock Units (“RSUs”) and 50% PSUs

❑ RSUs vest 1/3 per year

❑ PSUs - absolute total shareholder return (“ATSR”) calculation / cliff vest at end of year 3

❑ Targeted 3-year annualized return of 15% generates 100% of PSU grant

Strong Alignment with Shareholders

Disciplined Financial Management Liquidity

❑ Committed to maintaining a conservative capital

structure

❑ Target long-term leverage of <1.5x – 2.0x net debt /

Adjusted EBITDA

❑ Acquisitions to be funded through a mix of equity and

debt

❑ No existing hedges

PSUs - ATSR Hurdles

Borrowing Capacity as of 12.31.2019

Cash as of 12.31.2019

Borrowing

Base

Updated to

$180 MM in

February of

2020

0% of PSUs at <10% ATSR

100% of PSUs at 15% ATSR

MNRL

Three Months Ended

($ In thousands, except per share amounts) December 31,

2019 September 30,

2019

June 30,

2019

Adjusted EBITDA (1) $ 26,808 $ 19,286 $ 18,289

Less:

Adjusted EBITDA attributable to non-controlling interest (10,700 ) (10,931 ) (10,366 )

Adjusted EBITDA attributable to Class A Common Stock $ 16,108 $ 8,355 $ 7,923

Less:

Cash interest expense 421 72 550

Cash taxes 2,568 731 117

Dividend equivalent rights 248 224 —

Retained cash flow — — —

Less:

Lease bonus attributable to Class A Common Stock 300 421 641

Discretionary cash flow to Class A Common Stock ex Lease Bonus $ 12,571 $ 6,907 $ 6,615

Plus:

Lease bonus attributable to Class A Common Stock 300 421 641

Discretionary cash flow to Class A Common Stock $ 12,871 $ 7,328 $ 7,256

Plus:

Cash taxes 2,568 731 117

Discretionary cash flow to Class A Common Stock Pre-Tax 15,439 8,059 7,373

Shares of Class A Common Stock 34,181 21,997 21,997

Discretionary cash flow per share of Class A Common Stock ex. Lease Bonus $ 0.37 $ 0.31 $ 0.30

Discretionary cash flow per share of Class A Common Stock - Dividend $ 0.38 $ 0.33 $ 0.33

Discretionary cash flow per share of Class A Common Stock Pre-Tax $ 0.45 $ 0.37 $ 0.34

Quarterly Dividend

❑ Declared Q4 2019 dividend of $0.38 per share of Class A common stock

❑ Dividend to be paid on March 19, 2020 to holders of record as of March 12, 2020

❑ Anticipate gradually holding back cash flow in 2020 to fund a portion of ground game


(1)

(1)

MNRL

Guidance Ranges Low High

Daily Net Production (Boe/d) Sans Acquisitions 10,000 — 11,000

Oil Cut (%) 56% — 59%

Lease Bonus ($ millions) $4.5 — $6.0

Unit Costs ($/Boe)

Cash G&A Expense Plus Share Based Compensation Expense ($/Boe) $5.25 — $6.35

Cash G&A Expense ($/Boe) $3.60 — $4.10

Share Based Compensation Expense ($/Boe) $1.65 — $2.25

Gathering, Transportation, and Marketing ($/Boe) $1.65 — $2.25

Production Taxes (% of Revenue) 7% — 9%

Taxes

Tax Depletion ($/Boe) $9.00 — $11.50

Percent of Dividend Expected to be Return of Capital (Low: $55.00 / Bbl and High: $50.00 Flat Pricing) 50% — 70%

Mineral Acquisition Capital

Ground Game Acquisition Budget ($ millions) $160 — $240

2020 Operational and Financial Guidance

40% 2020 YoY Production Growth at Guidance Midpoint Excluding Acquisitions

❑ Raising the midpoint of base-asset production guidance by 500 Boe/d

❑ Operational costs consistent with historical results

❑ Lease bonus revenue estimated at greater than $4.5 million for the full year

❑ Ground game acquisition capital budget contemplating $40 MM to $60 MM of acquisitions per quarter

MNRL

Appendix

MNRL

-

20

40

60

80

100

-

100

200

300

400

500

2012 2013 2014 2015 2016 2017 2018 2019

Number of Deals Average NRA per Deal

Differentiated Technical Evaluation

Initial Vetting1

Operator Review2

Activity Analysis3

Inventory Potential4

EUR Analysis5

Financial Modeling6

Number of Deals and Avg NRA Per Deal

~1,500

Deals~82,200

NRA

MNRL

Springer28%

Woodford72%

Delaware45%

Midland7%

SCOOP7%

STACK14%

DJ18%

Williston3%

Other6%

Delaware31%

Midland5%

Scoop14%

Stack13%DJ

19%

Williston9%

Other9%

Anadarko Basin (SCOOP) OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

SCOOP

11,100

NRAs

Key Operators

Net Royalty Acres

8.4

Net Wells

1,092 gross wells


12,777 gross wells

MNRL DSUs

107.5

Net Wells



MNRL DSU Acreage

Active Rig

MNRL

Meramec45%

Woodford55%

Delaware45%

Midland7%

SCOOP7%

STACK14%

DJ18%

Williston3%

Other6%

Delaware31%

Midland5%

Scoop14%

Stack13%

DJ19%Williston

9%

Other9%

Anadarko Basin (STACK) OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

STACK

10,700

NRAs

Key Operators

Net Royalty Acres

1,752 gross wells


12,777 gross wells

MNRL DSUs

15.5

Net Wells

111.8

Net Wells



MNRL DSU Acreage

Active Rig

MNRL

Niobrara75%

Codell25%

Delaware45%

Midland7%

SCOOP7% STACK

14%

DJ18%

Williston3%

Other6%

Delaware31%

Midland5%

Scoop14% Stack

13%

DJ19%

Williston9%Other

9%

DJ Basin OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

Laramie

East

Pony

Wattenberg

DJ

15,600

NRAs

Key Operators

Net Royalty Acres

1,564 gross wells


12,777 gross wells

MNRL DSUs

19.9

Net Wells

111.8

Net Wells



MNRL DSU Acreage

Active Rig

MNRL

Wolfcamp A28%

Wolfcamp B27%

Lower Spraberry

33%

Other12%

Delaware45%

Midland7%

SCOOP7%

STACK14%

DJ18%

Williston3%

Other6%

Delaware31%

Midland5%

Scoop14%

Stack13%

DJ19%

Williston9%

Other9%

Midland Basin OverviewCore Outline Validated by Operator Rig Activity

Midland

4,100

NRAs

Key Operators

Net Royalty Acres

1,064 gross wells


12,777 gross wells

MNRL Core Outline

MNRL DSUs

7.5

Net Wells

111.8

Net Wells



MNRL DSU Acreage

Active Rig

MNRL

Bakken43%

Three Forks57%

Delaware45%

Midland7%

SCOOP7%

STACK14%

DJ18% Williston

3%

Other6%

Delaware31%

Midland5%

Scoop14%

Stack13% DJ

19%

Williston9%

Other9%

Williston Basin OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

Williston

7,750

NRAs

Key Operators

Net Royalty Acres

1,539 gross wells


12,777 gross wells

MNRL DSUs

3.0

Net Wells

111.8

Net Wells

MNRL DSU Acreage

Active Rig



MNRL

Mineral and Royalty Key Terms

Net mineral acres ◼ The full, undivided ownership of the oil, gas, and mineral

rights underneath one acre of land

Net royalty acre ◼ Net Mineral Acres standardized to a 12.5% (or 1/8) oil

and gas lease royalty

100% Royalty acres ◼ Net mineral acres standardized on a 100% (or 8/8) oil

and gas lease royalty basis

Drilling spacing units

(“DSUs”)

◼ 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

Implied average net

revenue interest per well

◼ Number of 100% oil and gas lease royalty acres per

gross DSU acre

Description How it’s calculated

◼ Total Brigham’s acreage

◼ 57,800

◼ Net mineral acres * Avg. royalty / (1/8)

◼ 82,200 = 57,800 * (18%) / (1/8)

◼ Net mineral acres * Avg. royalty

◼ 10,250 = 57,800 * 18%

◼ Total number of gross DSU acres

◼ 1,573,950

◼ 100% Royalty acres / Gross DSU acres

◼ 0.7% = 10,250 / 1,573,950

Note: As of December 31, 2019.

(1) Standardized to 1/8 royalty.

(2) Standardized to 100% royalty.

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

Net Mineral Acres

Weighted Avg.

Royalty Net Royalty Acres (1)

100% Royalty Acres (2)

Gross DSU Acres

Implied Average

Net Revenue

Interest Per Well (3)

Delaware 16,200 19.9% 25,750 3,200 301,500 1.1%

Midland 3,300 15.5% 4,100 500 84,550 0.6%

SCOOP 7,550 18.4% 11,100 1,400 204,600 0.7%

STACK 7,600 17.6% 10,700 1,350 179,950 0.8%

DJ 12,200 16.0% 15,600 1,950 171,950 1.1%

Williston 6,050 16.0% 7,750 950 487,600 0.2%

Other 4,900 18.4% 7,200 900 143,800 0.6%

TOTAL 57,800 17.8% 82,200 10,250 1,573,950 0.7%

MNRL

(in thousands)

December 31, September 30, December 31,

2019 2019 2018 2019 2018 2017

Production:

Daily production (Boe/d) 9,627 7,828 4,579 7,414 3,881 2,352

% Liquids 73% 69% 72% 71% 70% 66%

Revenue:

Royalty revenue $33,112 $24,135 $16,912 $97,886 $59,758 $30,066

Lease bonus and other revenue 502 972 679 3,629 7,506 10,842

Total revenue $33,614 $25,107 $17,591 $101,515 $67,264 $40,908

Other operating income:

Gain (loss) on sale of oil and gas properties, net – – – – – 94,551

Operating expense:

Gathering, transportation and marketing $1,235 $1,113 $1,050 $4,985 $3,944 $1,754

Severance and ad valorem taxes 2,203 1,377 937 6,409 3,536 1,601

Depreciation, depletion and amortization 10,630 8,434 4,306 30,940 13,915 6,955

General and administrative 5,184 5,068 2,566 21,963 6,638 3,935

Total operating expense $19,252 $15,992 $8,859 $64,297 $28,033 $14,245

Operating income $14,362 $9,115 $8,732 $37,218 $39,231 $121,214

Other income (expense):

Gain (Loss) on derivative instruments, net ($47) $91 $1,618 ($568) $424 ($121)

Interest expense, net (449) (65) (3,418) (5,609) (7,446) (556)

Loss on extinguishment of debt 41 – (6,892)

Gain (Loss) on sale of equity securities – – – – 823 (4,222)

Other income, net 4 130 53 169 110 305

Income before taxes $13,911 $9,271 $6,985 $24,318 $33,142 $116,620

Tax expense (benefit) 1,565 807 (129) 2,679 327 1,008

Net income $12,346 $8,464 $7,114 $21,639 $32,815 $115,612

Less: net income attributable to predecessor – – $6,166 ($5,092) ($30,976) ($115,612)

Less: (net income) loss attributable to temp equity ($7,269) ($5,318) – ($9,646) – –

Net income (loss) attributable to shareholders $5,077 $3,146 $948 $6,901 $1,839 –

Other Financial Data:

Adjusted EBITDA $26,808 $19,286 $13,038 $78,207 $53,146 $33,618

Adjusted EBITDA ex lease bonus 26,306 18,314 12,359 74,578 45,640 22,776

Adjusted EBITDA margin (Divided By Total Rev.) 80% 77% 74% 77% 79% 82%

Balance Sheet Data:

Cash and cash equivalents $51,133 $25,848 $31,985 $51,133 $31,985 $6,886

Total assets 784,162 716,204 554,026 784,162 554,026 334,477

Credit facilities – 45,000 170,705 – 170,705 27,000

Total liabilities 12,336 52,740 180,078 12,336 180,078 32,303

Total equity 317,319 59,478 373,948 317,319 373,948 302,174

Temporary equity 454,507 603,986 – 454,507 – –

Three Months Ended

Year Ended December 31,

Historical Financial Summary

MNRL

(in thousands)

December 31, September 30, December 31,

2019 2019 2018 2019 2018 2017

Net Income $12,346 $8,464 $7,114 $21,639 $32,815 $115,612

Add:

Loss on extinguishment of debt (41) – – 6,892 – –

Adjusted net income $12,305 $8,464 $7,114 $28,351 $32,815 $115,612

Add:

Depreciation, depletion and amortization 10,630 8,434 4,306 30,940 13,915 6,955

Interest expense, net 449 65 3,418 5,609 7,446 556

Share based compensation expense 1,816 1,737 – 10,049 – –

(Gain) / Loss on distribution of equity securities – – – – – 4,222

Loss on commodity derivative instruments, net 47 – – 568 – 121

Income tax expense 1,565 807 – 2,679 327 1,008

Less:

Gain on derivative instruments, net – 91 1,618 – 424 –

Other income, net 4 130 53 169 110 305

Gain on sale of oil and gas properties – – – – – 94,551

Gain on distribution of equity securities – – – – 823 –

Income tax benefit – – 129 – – –

Adjusted EBITDA $26,808 $19,286 $13,038 $78,207 $53,146 $33,618

Less:

Lease bonus 502 972 679 3,629 7,506 10,842

Adjusted EBITDA ex lease bonus $26,306 $18,314 $12,359 $74,578 $45,640 $22,776

Adjusted EBITDA $26,808 $19,286 $13,038 $78,207 $53,146 $33,618

Less:

EBITDA attributable to temporary equity (10,700) (10,931) – (32,061) – –

EBITDA attributable to Class A Common Stock $16,108 $8,355 $– $46,146 $– $–

Less:

Cash interest expense 421 72 – 1,043 – –

Cash taxes 2,568 731 – 3,416 – –

Dividend Equivalent Rights 248 224 – 472 – –

Retained Cash Flow – – – – – –

Discretionary cash flow available to Class A Common Stock $12,871 $7,328 $– $41,215 $– $–

Memo: Adjusted EBITDA margin

Revenue 33,614 25,107 17,591 101,515 67,264 40,908

Adjusted EBITDA 26,808 19,286 13,038 78,207 53,146 33,618

Adjusted EBITDA Margin (%) 80% 77% 74% 77% 79% 82%

Three Months Ended

Year Ended December 31,

Non-GAAP Reconciliations

q4 2019 investor presentation · q4 2019 summary statistics ~125 total operators operator exposure...

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