Q2 2020 Investor Presentation...Q2 2020 Investor Presentation August 2020. Page 2 MNRL Disclaimer The financial projections and other estimates contained herein are forward-looking

Q2 2020 Investor PresentationAugust 2020

Page 2MNRL

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 ongoing spread and economic effects of COVID-19, potential future pandemics, the actions of the Organization of Petroleum Exporting Countries and other significant producers and governments and the ability

of such producers to agree to and maintain oil price and production controls, the proximity to and capacity of transportation and storage 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 LTM 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 LTM 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 LTM 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 over the last twelve months. 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 LTM 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 LTM 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 LTM 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 LTM 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.

Page 3MNRL

High operating margins

Differentiated PositioningStrength and Opportunity Through the Commodity Cycle

Balance sheet flexibility to both acquire and

distribute to shareholders

Acquisition markets thawing / restarting

ground game

Cash salaries only / no management cash

bonuses

Advantaged

Business

Model

Capital

Structure

Commitment to

Shareholders

Disciplined

Acquisition

Strategy

NYSE:

MNRL

Perpetual asset with significant optionality

No D&C capex or lease operating expenses

Total liquidity of > $150 M

Commitment to limit Net Debt / Adjusted LTM EBITDA to 1.5 – 2.0x (1)

Experienced technical team

Conserved capital in Q1 and Q2 for better environment

Equity comp aligned with shareholders through total

stock return benchmark

Employee safety a priority

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

Page 4MNRL

3.9x

2.5x

1.8x

1.1x

<0.0x0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

5.0x

Peer A Peer B Peer C Peer D MNRL -

50

100

150

200

250

300

350

400

450

500

2Q19 3Q19 4Q19 1Q20 2Q20

MNRL Peers

MNRL – Advantaged Balance SheetMNRL Cash Flow Unencumbered by Interest Expense or Hedge Losses

No Debt + No Punitive Hedges + Core Assets = More Capital to

Shareholders

Indexed Cumulative Dividend / Share (3)

MNRL Positive

Cash Position to

Return Capital to

Shareholders

and Fund

Acquisitions

~$1,585 M of Cumulative Debt

and Preferred Equity Sitting

Atop the Common Equity

Across the Peer Group

(1) Peers include, in alphabetical order: BSM, FLMN, KRP and VNOM. (2) See Appendix to this presentation for GAAP to Non-GAAP reconciliations. (3) Indexed to Q2 2019 dividend.

MNRL has Returned

More Cash to

Shareholders on Both

an Absolute and

Relative Basis Per

Share than Each of its

Peers Over the Last

Twelve Months

Net Debt / Adj. LTM EBITDA (1) (2)

(1)

Page 5MNRL

Q2 2020 Net Production (8,854 Boe/d)

Q2 2020 Summary Statistics

OXY12%

CVX8%

OVV6%

CLR5%

MRO4%

XEC4%

DVN4%XOM

4%

EOG3%

FANG3%

PRI3%

CPE3%

RDS3%PXD

3%

WLL2%

PDCE2%

PE2%

XOG2%

Camino2%

CXO2%

Other Public8%

Other Private14%

~125 total

operators

Operator Exposure by NRI (3)(4)

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

Net Mineral Acres 58,900 (18% RI)

Net Royalty Acres 83,575 (12.5% RI)

Net Production 8,854 Boe/d

Adjusted EBITDA (2) $5.9 M

Gross / Net Hz Producing well count 5,444 / 33

Gross / Net Hz Undeveloped well count 12,907 / 113

Gross / Net Spuds 36 / 0.2

Gross / Net DUCs 705 / 4.6

Gross / Net Active Permits 735 / 4.5

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

71%

Liquids

Source: Company data, Q2 2020 Internal Reserves, Drilling Info, IHS. Data as of 6/30/2020.

(1) Other includes Extended Woodford and Merge.


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

(4) Pro forma for prospective combination of CVX and NBL.

83,575

NRA

Delaware, 26,550 , 32%

Midland, 4,800 , 6%

SCOOP, 11,375 , 13%

STACK, 10,700 , 13%

DJ, 15,600 , 19%

Williston, 7,825 , 9%

Other, 6,725 , 8%

Oil50%

Gas29%

NGL21%

Delaware Midland

SCOOP/STACK

Williston

DJ

Page 6MNRL

82 99

208

150

230 248

214 185

209

36

0

50

100

150

200

250

300

350

400

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

Other Williston DJ Basin STACK SCOOP Midland Delaware

Gross Spuds

6,768

7,828

9,627

10,401

8,854

-

2,000

4,000

6,000

8,000

10,000

12,000

2Q19 3Q19 4Q19 1Q20 2Q20

0.33

1.07

1.42

1.04

1.21 1.32 1.31

1.70 1.60

0.21

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

Other Williston DJ Basin STACK SCOOP Midland Delaware

Net Spuds

Production & Activity UpdateInventory of Activity Wells to Drive 2H20

Source: Company filings and Drilling Info.

Note: DUC inventory from the internal MNRL Q2 2020 reserve report.

Quarterly Gross Well Spuds

Quarterly Net Well Spuds

Boe/d Prior Period Gross DUCs

Net Production and DUC Inventory

Entering 2H20 with Line of Sight to

Activity: 4.6 Net DUCs and 4.5 Net

Permits

Gross DUC Conversion

4Q19

Converted

38%3Q19

Converted

26%

1Q20

Converted

28%

2Q19

DUCs

943

3Q19

DUCs

996

4Q19

DUCs

892

1Q20

DUCs

882

2Q20

Converted

25%

2Q20

DUCs

705

Page 7MNRL

31.6 32.9

0.1 1.2 0.0 0.0 0.0

0.0

10.0

20.0

30.0

40.0

Q1 2020 PDP Acquired Wells Converted DUC ConvertedPermitted

ConvertedUnpermitted

Other Q2 2020 PDP

5.7 4.6 (1.2)

0.0 0.2 0.0 0.1

0.0

2.0

4.0

6.0

8.0

Q1 2020 DUCs Converted toPDP

Acquired Wells ConvertedPermit


Other Q2 2020 DUCs

882 705

(222)

6 29 7

3

0

250

500

750

1,000

Q1 2020 DUCs Converted toPDP

Acquired Wells ConvertedPermit


Other Q2 2020 DUCs

5,234 5,444

7 222 0 0 19

3,000

3,750

4,500

5,250

6,000

Q1 2020 PDP Acquired Wells Converted DUC ConvertedPermitted


Other Q2 2020 PDP

Location ConversionMNRL Holds 4.6 Net DUCs Headed Into 2H20

MNRL had 1.2 Net Wells TIL in Q2 2020 Despite Industry Wide Activity

Reduction

222 Gross Wells

and 1.2 Net

Wells Converted

into PDP During

Q2 2020

36 Gross Wells

and 0.2 Net

Wells Converted

to DUCs During

Q2 2020

PDP Conversions

DUC Conversions

Page 8MNRL

PD /

DSU., 3.9

Undev. /

DSU.,

11.2

PD /

DSU., 3.3

Undev. /

DSU., 5.7

PD /

DSU., 2.2

Undev. /

DSU., 9.2

PD /

DSU., 7.0

Undev. /

DSU., 8.3

PD /

DSU., 5.3

Undev. /

DSU., 4.3

PD /

DSU., 3.8

Undev. /

DSU., 8.0

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

NRA / % of Total 26,550 / 32% 4,800 / 6% 11,375 / 13% 10,700 / 13% 15,600 / 19% 7,825 / 9% 83,575 / 100%

Q2 2020 Production (Boe/d) / % of

Total4,653 / 53% 391 / 4% 1,049 / 12% 939 / 11% 1,188 / 14% 572 / 7% 8,854 / 100%

Production by Product (2)

Gross / Net DUCs 198 / 2.1 157 / 0.7 69 / 0.4 8 / 0.0 128 / 1.1 138 / 0.3 705 / 4.6

Gross / Net Permits 165 / 1.3 119 / 0.5 12 / 0.1 9 / 0.0 214 / 2.2 209 / 0.4 735 / 4.5

3P Wells per DSU (3)

Gross / Net Spuds 16 / 0.1 3 / 0.0 4 / 0.0 0 / 0.0 2 / 0.0 11 / 0.0 36 / 0.2

Top Operators

PD /

DSU., 3.1

Undev. /

DSU.,

11.2

Oil50%

Gas29%

NGL21%

Oil52%

Gas21%

NGL27%

Oil42%

Gas46%

NGL12%Oil

29%

Gas44%

NGL27%Oil

36%

Gas49%

NGL15%

Oil70%

Gas9%

NGL21%

Oil58%Gas

20%

NGL22%

Portfolio Area OverviewCore Position in Premier Liquids-Rich Basins

14.33P/DSU

15.03P/DSU

9.03P/DSU

11.53P/DSU

15.33P/DSU

9.53P/DSU

11.83P/DSU

80%

Liquids

92%

Liquids

51%

Liquids

56%

Liquids

54%

Liquids

79%

Liquids

71%

Liquids

Note: Includes only Horizontal Locations.

(1) Includes Extended Woodford, Merge and Marcellus.

(2) Product mix displayed for Q2 2020.

(3) 3P wells per DSU from Q2 2020 Internal Reserve Report.

Page 9MNRL

394 373 388

199125

7847 43

14

9

51

40 37

11

5

51

45 45

18

10

0

100

200

300

400

500

600

700

Q3 2019 Q4 2019 Q1 2020 Q2 2020 Current

Permian Anadarko Niobrara Bakken

110 100 89

2235

21

1012

2

3

19

1910

30

20

19

16

24

0

30

60

90

120

150

180

210

Q3 2019 Q4 2019 Q1 2020 Q2 2020 Current

Permian Anadarko Niobrara Bakken

Disciplined Acquisition StrategyTargeting Activity in the Down Market

Key Area Horizontal Rig Counts (LTM)

Frac Crew Counts (LTM)

Continuing to focus on acquisitions in the

Delaware and Midland Basins

Targeting most resilient activity with frac

crews up ~50% from May lows

Acquisition Strategy

Not acquiring under bankrupt or struggling

operators

Focusing on operators with the lowest cost

inventory

Location

Seeking low cost per net location and an

optimized blend of PDP, DUCs and

undeveloped, still adhering to the principle of

buying substantial undeveloped inventory

while also returning cash to shareholders in

the near-term

Quality Operators

Return Focused Strategy

Source: Rig data via Tudor Pickering Holt & Co. Equity Research. Frac crew counts via Kayrros Energy.

Page 10MNRL

6%

DUCs &

Permits

PDP21%

DUCs3%

Permits3%

Unpermitted73%

7%

DUCs &

Permits

PDP21%

DUCs4%

Permits3%

Unpermitted72%

7%

DUCs &

Permits

PDP21%

DUCs4%

Permits3%

Unpermitted72%

60%72%

45%62%

-

11%6%

11%

27%

84%

0%

20%

40%

60%

80%

100%

2Q2019 3Q2019 4Q2019 1Q2020 2Q2020

Delaware Midland SCOOP STACK DJ Williston Other

1H2019 Acquisitions $7.6 mm / 8%

3Q2019 Acquisitions $11.0 mm / 24%

4Q2019 Acquisitions $7.2 mm / 19%1Q2020 Acquisitions

$6.7 mm / 7% $-

$4

$8

$12

$16

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

Acquisition SummaryQ2 2020 Acquisitions

Decrease in $ / Net Well Valuation Creates Attractive Buying Opportunities

Q2 2020 Acquisition Net Well by Type% of Net Wells by Type at end of Q1 2020 % of Net Wells by Type at end of Q2 2020

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

$M / Net Well

Permian Weighted with Opportunities Across Basins % of Net DUCs and Permits Drives $ / Net Well

At of the end of Q1 2020 and

prior to conversions during Q2 2020

1H2019 Acquisitions $7.6 M / 8%

Q3 2019 Acquisitions $11.0 M / 24%




Est. Q3 2020 Acquisitions $3.7 M / 5% (1) $-

$2

$4

$6

$8

$10

$12

$14

$16

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

(1) Includes approximately $15 M of closed and pending acquisitions as of August 10, 2020.

Page 11MNRL

MNRL DSUs

Delaware Basin Q3 2020 AcquisitionsGround Game Acquisition Activity Accelerating with Focus on Permian Consolidation

Source: Public Data, DrillingInfo and IHS.

Note: Asset data as of August 10, 2020.

Active Rig

MNRL DSU Acreage

Recent MNRL Acquisition Activity

Primarily targeting core Permian undeveloped

with substantial upper Wolfcamp inventory

remaining

Acquisition Strategy

Undeveloped DSUs acquired under operators

with active rig fleets

Location

Oil weighted acquisitions (> 50% oil cut)

excellent blend of developed and

undeveloped acreage

Retaining substantial upper Wolfcamp

inventory at attractive multiples ~$4 M per net

location

Quality Operators

Return Focused Strategy

MNRL Core Outline

Loving County

Development Area

Page 12MNRL

Approaching Mineral Acquisition Opportunities with Patience and Discipline

Investment Thesis

Decisive Management Responses to Challenging Environment

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

Undeveloped Core Inventory Drives Capex Free Long-Term Organic Growth

Experienced and Technically Focused Team with Strong Shareholder Alignment

Cash on Balance Sheet / No Debt Outstanding / $135 M Undrawn Revolver

Page 13Page 13MNRL

Portfolio Overview & Highlights

Page 14MNRL

6,149

12,907

19,056

Inventory

3P (68%)

PD (32%)

8%

12%

12%

14%

8%

10%

37%

Undeveloped Locations

Delaware

Midland

SCOOP

STACK

DJ

Williston

Other

9.03P/DSU

Undeveloped Gross LocationsTotal Gross Locations

Source: MNRL Q2 2020 Internal Reserve Report.

(1) Other includes Extended Woodford and Merge.

(2) Inventory life calculated as 3P undeveloped locations divided by LTM gross wells spud.

20 Years of

Inventory

Life(2)

Substantial Organic Inventory47% of Gross & 53% of Net Undeveloped Locations in Permian

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

15.33P/DSU

9.53P/DSU

PD / DSU Undev / DSU

STACK Wells per DSU DJ Wells per DSU

14.33P/DSU

15.03P/DSU

(1)

PD /

DSU., 5.3

Undev. /

DSU., 4.3

PD /

DSU., 7.0

Undev. /

DSU., 8.3

PD /

DSU., 2.2

Undev. /

DSU., 9.2

PD /

DSU., 3.3

Undev. /

DSU., 5.7

PD /

DSU., 3.9

Undev. /

DSU.,

11.2

PD /

DSU., 3.1

Undev. /

DSU.,

11.2

Page 15MNRL

7.0

1.7

1.3

5.0

14.7

8.6

6.9

6.1

2.2

1.0

3.0

2.2

2.4

5.4

0.6

3.7

6.2

12.6

22.4

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

1,032

821

695

397

1,150

988

760

771

300

121

439

326

344

441

151

475

665

1,090

1,941

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 – (113.2)Gross Horizontal Well Locations - (12,907)

53% of Net Locations in Permian and 35% of Net Locations are Wolfcamp

Source: MNRL Q2 2020 Internal Reserve Report.

Organic Undeveloped Inventory20 Year Organic Inventory to Drive Long-Term Production and Cash Flow

10%

8%

12%

12%

37%

8%

14%

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

8%

7%

17%

3%

45%

6%

14%

Page 16MNRL

Delaware32%

Midland6%SCOOP

13%

STACK13%

DJ19%

Williston9%

Other8%

MNRL DSUs

Delaware Basin OverviewCore Outline Validated by Operator Rig Activity

Delaware

26,550

NRAs

Key Operators

Undeveloped Well Locations

Net Royalty Acres

51.0

Net Wells

MNRL Core Outline

4,763 gross wells12,907 gross wells

Loving County

Development Area

113.2

Net Wells


Note: Asset data as of June 30, 2020.

MNRL DSU Acreage

Active Rig

Wolfcamp A44%

Wolfcamp B25%

3rd BS / WC XY

12%2nd Bone

Spring7%

Avalon1%

Other11%

Delaware45%

Midland8%

SCOOP7%

STACK14%

DJ17%

Williston3%

Other6%

Page 17Page 17MNRL

Financial Overview

Page 18MNRL

Financial Policies

10%

15%

25%

0%

100%

200%

300%

0%

10%

20%

30%

Annualized Return % of PSU Target Earned

❑ 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 PSUs - ATSR Hurdles

0% of PSUs at <10% ATSR

100% of PSUs at 15% ATSR

$16

$135

$151

1Borrowing Capacity 06.30.2020

Cash 06.30.2020

Disciplined Financial Management Liquidity ($M)

❑ Committed to maintaining a conservative capital

structure

❑ Limit long-term leverage to <1.5x – 2.0x net debt /

Adjusted LTM EBITDA (1)

❑ Acquisitions to be funded through a mix of cash on

balance sheet, debt and equity


Page 19MNRL

❑ Declared Q2 2020 dividend of $0.14 per share of Class A common stock

❑ Dividend to be paid on September 3, 2020 to holders of record as of August 27, 2020

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

Quarterly Dividend

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

(2) The Company does not expect to incur federal income taxes for income related to results for the six months ended June 30, 2020.

($ In thousands, except per share amounts)

Adjusted EBITDA (1) $ 5,909 $ 25,123

Less:

Adjusted EBITDA attributable to non-controlling interest $ (10,029)

Adjusted EBITDA attributable to Class A Common Stock $ 4,080 $ 15,094

Less:

Cash interest expense

Cash taxes (2)

Dividend equivalent rights

Retained cash flow

Less:

Lease bonus attributable to Class A Common Stock

Discretionary cash flow to Class A Common Stock ex Lease Bonus (1) $ 5,446 $ 10,198

Plus:

Lease bonus attributable to Class A Common Stock

Discretionary cash flow to Class A Common Stock (1) $ 5,489 $ 12,546

Shares of Class A Common Stock

Discretionary cash flow per share of Class A Common Stock ex. Lease Bonus $ 0.14 $ 0.30

Discretionary cash flow per share of Class A Common Stock - Dividend $ 0.14 $ 0.37

39,297 34,174

43 2,348

43 2,348

462 360

— —

165 152

(2,036) 2,036

Three Months Ended

30-Jun-20 31-Mar-20

(1,829)

Page 20Page 20MNRL

Appendix

Page 21MNRL

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 16,850 19.7% 26,550 3,300 317,100 1.0%

Midland 3,900 15.4% 4,800 600 94,460 0.6%

SCOOP 7,750 18.3% 11,375 1,400 207,200 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 16.2% 7,825 1,000 490,150 0.2%

Other 4,550 18.5% 6,725 850 145,050 0.6%

TOTAL 58,900 17.7% 83,575 10,450 1,605,860 0.7%

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

◼ 58,900

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

◼ 83,575 = 58,900 * (18%) / (1/8)

◼ Net mineral acres * Avg. royalty

◼ 10,450 = 58,900 * 18%

◼ Total number of gross DSU acres

◼ 1,605,860

◼ 100% Royalty acres / Gross DSU acres

◼ 0.7% = 10,450 / 1,605,860

Note: As of June 30, 2020.

(1) Standardized to 1/8 royalty.

(2) Standardized to 100% royalty.

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

Page 22MNRL

$8.2 $9.4

$8.4 $7.4

$4.0

($3.2)

$8.5

$12.3

$8.8

($6.8)

$(10)

$(5)

$-

$5

$10

$15

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

76%82% 83%

74% 76% 75% 77%80% 78%

47%

0%

20%

40%

60%

80%

100%

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

Quarterly Financial Results

Total Revenue and Realized Price

Net Income(1)

Adjusted EBITDA(2)

Adjusted EBITDA Margin(2)

$ in millions and $ / Boe $ in millions

(1) Reflects combined recast financials.

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

(3) Adjusted Net Income of $3.7 million.

(2) (3)

Realized Price

Revenue Lease Bonus

EBITDA Ex. Lease Bonus

$14.1

$16.9 $18.7

$17.6 $18.3

$24.5 $25.1

$33.6 $32.3

$12.6

$40.54$42.87

$45.26

$40.15

$36.31

$37.42$33.51

$37.39

$29.98

$15.57

$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 1Q20 2Q20

$8.5

$11.4 $13.3

$12.4 $13.1

$16.8 $18.3

$26.3

$21.2

$5.8

$10.8

$13.8 $15.5

$13.0 $13.8

$18.3 $19.3

$26.8 $25.1

$5.9

$-

$5

$10

$15

$20

$25

$30

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

Page 23MNRL

(in thousands) Three Months Ended

June 30, March 31, June 30,

2020 2020 2019 2019 2018

Production:

Daily production (Boe/d) 8,854 10,401 6,768 7,414 3,881

% Liquids 71% 72% 71% 71% 70%

Revenue:

Royalty revenue $12,543 $28,374 $23,049 $97,886 $59,758

Lease bonus and other revenue 62 3,906 1,480 3,629 7,506

Total revenue $12,605 $32,280 $24,529 $101,515 $67,264

Other operating income:

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

Operating expense:

Gathering, transportation and marketing $1,625 $1,779 $1,523 $4,985 $3,944

Severance and ad valorem taxes 1,034 1,752 1,450 6,409 3,536

Depreciation, depletion and amortization 11,200 12,826 6,760 30,940 13,915

General and administrative 5,890 5,510 9,762 21,963 6,638

Total operating expense $19,749 $21,867 $19,495 $64,297 $28,033

Operating (loss) income ($7,144) $10,413 $5,034 $37,218 $39,231

Other income (expense):

Gain (Loss) on derivative instruments, net $73 ($568) $424

Interest expense, net (545) (32) (1,270) (5,609) (7,446)

Loss on extinguishment of debt – – (6,933) (6,892)

Gain on sale of equity securities – – – – 823

Other income, net 23 2 6 169 110

(Loss) Income before taxes ($7,666) $10,383 ($3,090) $24,318 $33,142

Tax (benefit) expense (850) 1,582 117 2,679 327

Net (loss) income ($6,816) $8,801 ($3,207) $21,639 $32,815

Less: net income attributable to predecessor – – ($1,590) ($5,092) ($30,976)

Less: net loss (income) attributable to temp equity $2,766 ($4,095) $2,941 ($9,646) –

Net (loss) income attributable to shareholders ($4,050) $4,706 ($1,856) $6,901 $1,839

Other Financial Data:

Adjusted EBITDA $5,909 $25,123 $18,289 $78,207 $53,146

Adjusted EBITDA ex lease bonus 5,847 21,217 16,809 74,578 45,640

Adjusted EBITDA margin (Divided By Total Rev.) 47% 78% 75% 77% 79%

Balance Sheet Data:

Cash and cash equivalents $16,465 $30,979 $82,727 $51,133 $31,985

Total assets 742,892 769,582 677,642 784,162 554,026

Credit facilities – – – – 170,705

Total liabilities 9,944 9,130 7,224 12,336 180,078

Total equity 518,802 519,633 58,456 317,319 373,948

Temporary equity 214,146 240,819 611,962 454,507 –

Year Ended December 31,

Historical Financial Summary

Note: Reflects combined recast financials.

Page 24MNRL

Non-GAAP Reconciliations

Note: Reflects combined recast financials.

(in thousands)

Jun. 30, Mar. 31, Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Sep. 30, Jun. 30, Mar. 31,

2020 2020 2019 2019 2019 2019 2018 2018 2018 2018 2019 2018

Net Income (6,816) $8,801 $12,346 $8,464 ($3,207) $4,036 $7,114 $8,153 $9,351 $8,196 $21,639 $32,815

Add:

Loss on extinguishment of debt – – (41) – 6,933 – – – – – 6,892 –

Adjusted net income (6,816) $8,801 $12,305 $8,464 $3,726 $4,036 $7,114 $8,153 $9,351 $8,196 $28,531 $32,815

Add:

Depreciation, depletion and amortization 11,200 12,826 10,630 8,434 6,760 5,116 4,306 3,851 3,213 2,545 30,940 13,915

Interest expense, net 545 32 449 65 1,270 3,825 3,418 2,902 652 474 5,609 7,446

Share based compensation expense 1,853 1,884 1,816 1,737 6,495 – – – – – 10,049 –

(Gain) / Loss on distribution of equity securities – – – – – 685 – – – – – –

Loss on commodity derivative instruments, net – – 47 – – – – 280 555 359 568 –

Income tax expense – 1,582 1,565 807 117 190 – 428 12 16 2,679 327

Less:

Gain on derivative instruments, net – – – 91 73 – 1,618 – – – – 424

Other income, net 23 2 4 130 6 29 53 47 6 3 169 110

Gain on sale of oil and gas properties – – – – – – – – – – – –

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

Income tax benefit 850 – – – – – 129 – – – – –

Adjusted EBITDA $5,909 $25,123 $26,808 $19,286 $18,289 $13,823 $13,038 $15,567 $13,777 $10,764 $78,207 $53,146

Adjusted LTM EBITDA (Rolling) $77,126 $89,506 $78,206 $64,436 $60,717 $56,205 $53,146

Less:

Lease bonus 62 3,906 502 972 1,480 675 679 2,241 2,367 2,219 3,629 7,506

Adjusted EBITDA ex lease bonus $5,847 $21,217 $26,306 $18,314 $16,809 $13,148 $12,359 $13,326 $11,410 $8,545 $74,578 $45,640

Adjusted EBITDA $5,909 $25,123 $26,808 $19,286 $18,289 $13,823 $13,038 $15,567 $13,777 $10,764 $78,207 $53,146

Less:

EBITDA attributable to temporary equity (1,829) (10,029) (10,700) (10,931) (10,366) – – – – – (32,061) –

EBITDA attributable to Class A Common Stock $4,080 $15,094 $16,108 $8,355 $7,923 $– $– $– $– $– $46,146 $–

Less:

Cash interest expense 165 152 421 72 550 – – – – – 1,043 –

Cash taxes (2,036) 2,036 2,568 731 117 – – – – – 3,416 –

Dividend Equivalent Rights 462 360 248 224 – – – – – – 472 –

Retained Cash Flow – – – – – – – – – – – –

DsCF available to Class A Common Stock $5,489 $12,546 $12,871 $7,328 $7,256 $– $– $– $– $– $41,215 $–

Memo: Adjusted EBITDA margin

Revenue 12,605 32,280 33,614 25,107 24,529 18,265 17,591 18,701 16,889 14,083 101,515 67,264

Adjusted EBITDA $5,909 $25,123 $26,808 $19,286 $18,289 $13,823 $13,038 $15,567 $13,777 $10,764 $78,207 $53,146

Adjusted EBITDA Margin (%) 47% 78% 80% 77% 75% 76% 74% 83% 82% 76% 77% 79%

Year Ended December 31,

Three Months Ended

Page 25MNRL

Midland Basin OverviewCore Outline Validated by Operator Rig Activity

Midland

4,800

NRAs

Key Operators

Net Royalty Acres

1,230 gross wells


12,907 gross wells

MNRL Core Outline

MNRL DSUs

8.6

Net Wells

113.2

Net Wells



MNRL DSU Acreage

Active Rig

Delaware45%

Midland8%

SCOOP7%

STACK14%

DJ17%

Williston3%

Other6%

Wolfcamp A28%

Wolfcamp B26%

Lower Spraberry

35%

Other11%

Delaware32%

Midland6%

SCOOP13%

STACK13%

DJ19%

Williston9%

Other8%

Page 26MNRL

Delaware32%

Midland6%

SCOOP13%

STACK13%

DJ19%

Williston9%Other

8%

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

1,547 gross wells


12,907 gross wells

MNRL DSUs

19.7

Net Wells

113.2

Net Wells



MNRL DSU Acreage

Active Rig

Niobrara75%

Codell25%

Delaware45%

Midland8%

SCOOP7% STACK

14%

DJ17%

Williston3%

Other6%

Page 27MNRL

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

MNRL Core Outline

SCOOP

11,375

NRAs

Key Operators

Net Royalty Acres

8.3

Net Wells

1,071 gross wells


12,907 gross wells

MNRL DSUs

113.2

Net Wells



MNRL DSU Acreage

Active Rig

Delaware45%

Midland8%

SCOOP7%

STACK14%

DJ17%

Williston3%

Other6%

Delaware32%

Midland6%

SCOOP13%

STACK13%DJ

19%

Williston9%

Other8%

Springer27%

Woodford73%

Page 28MNRL

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

MNRL Core Outline

STACK

10,700

NRAs

Key Operators

Net Royalty Acres

1,748 gross wells


12,907 gross wells

MNRL DSUs

15.6

Net Wells

113.2

Net Wells



MNRL DSU Acreage

Active Rig

Meramec45%

Woodford55%

Delaware45%

Midland8%

SCOOP7%

STACK14%

DJ17%

Williston3%

Other6%

Delaware32%

Midland6%

SCOOP13%

STACK13%

DJ19%Williston

9%

Other8%

Page 29MNRL

Delaware32%

Midland6%

SCOOP13%

STACK13% DJ

19%

Williston9%

Other8%

Williston Basin OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

Williston

7,825

NRAs

Key Operators

Net Royalty Acres

1,516 gross wells


12,907 gross wells

MNRL DSUs

3.0

Net Wells

113.2

Net Wells

MNRL DSU Acreage

Active Rig



Bakken43%

Three Forks57%

Delaware45%

Midland8%

SCOOP7%

STACK14%

DJ17%

Williston3%

Other6%

Documents

Q2 2020 Investor Presentation...Q2 2020 Investor Presentation August 2020. Page 2 MNRL Disclaimer The financial projections and other estimates contained herein are forward-looking