2Q19 Investor Presentation...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

2Q19 Investor PresentationAugust 2019

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 risks include, but are not limited to, commodity price volatility, the Company’s dependence on third party operators to develop and operate its acreage, the Company’s ability to identify, complete

and integrate acquisitions, regulatory changes, lack of availability of drilling and production equipment, services and personnel, and the uncertainty inherent in estimating oil and natural gas reserves and in projecting future

rates of production. 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.

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

EBITDA, Adjusted EBITDA ex lease bonus 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 discretionary cash flow as Adjusted EBITDA less cash interest expense and cash taxes.

Adjusted net income, Adjusted EBITDA, Adjusted EBITDA ex lease bonus 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 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 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 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 the registration statement, prospectus and 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

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

Founders

Successfully acquired ~74,100 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, & Williston

Portfolio Areas

Sophisticated and Technically Disciplined

Evaluation Model Leveraging E&P Experience to

Acquire Minerals

(1) As of June 30, 2019.

Business Plan

Market Snapshot (1)

NYSE Ticker: MNRL

Market Cap: $1.1 billion

Share Count: 50.8 million

Net Debt: ($83) million

Liquidity: $203 million

Structure: C-corp

Bud Brigham

Rob Roosa

Page 4MNRL

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

2019 Increased Net Mineral Position by 8% YTD

2019IPO / Acquire & Consolidate

Page 5MNRL

Delaware29%

Midland5%

SCOOP14%

STACK14%

DJ21%

Williston9%

Other8%

OXY11%

NBL9%

ECA5%

DVN5%CLR

4%BP4%

XEC4%

FANG3%

PXD3%

XOM3%

HK

PRI

XOG

WLL

PDCE

CXO

CVX

VERDAD

CROSSING ROCKS

EOG

Other Public11%

Other Private17%

Chart Title

Summary Statistics

Delaware Midland

SCOOP/STACK

Williston

DJ

Oil56%

NGL15%

Gas29%

~115 total

operators

Operator Exposure by NRI (4)(5)

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

Net Mineral Acres 51,900 (18% RI)

Net Royalty Acres 74,100 (12.5% RI)

2Q19 Net Production 6,768 Boe/d

2Q19 Adjusted EBITDA (2) $18.3 million

Gross / Net Hz Producing well count 3,920 / 22

Gross / Net Hz Undeveloped well count 12,085 / 104

Gross Avg. Hz Rigs Running 2Q 2019 (6/30/19) 62

Gross / Net DUCs (6/30/19) 943 / 5.3

Gross / Net Active Permits (6/30/19) (3) 680 / 3.6

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

6,768

boe/d

Source: Company data, 2Q 2019 Internal Reserves, RSEG. Data as of 6/30/2019.

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

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

(3) Permit count excludes Laramie County, Wyoming.

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

(5) All Occidental statistics pro forma for announced merger with Anadarko.

2Q19 Net Production

74,100

NRA

Page 6MNRL

84

49

43

8

1

MNRL FLMN VNOM KRP BSM

Brigham’s Differentiated PositioningDiversified High Growth Vehicle

Source: Public data and PLS.

Peers: BSM, FLMN, KRP, and VNOM.

(1) Acreage normalized on a 1/8th equivalent basis. MNRL 2Q19 rig average and NRA as of June 30, 2019, 62 rigs * 100,000 NRA / 74,100 NRA. Based on most recent public data.

Rigs on Position Scaled to 100K NRA per Company (1)

Peer A

Liquids Rich Shale Basins

MNRL

Peer C

Peer D

Co 1 / Co 2 Overlap

> 1.7x the rig density of

any other public mineral

company

Brigham Minerals is diversified where it matters

Diversified Acreage Position Across Liquids Rich Resource Plays

Peer B Peer C Peer D

Page 7MNRL

$30

$35

$40

$45

$50

$55

$60

$65

$70

4Q18 1Q19 2Q19

MNRL Peer 1 Peer 2

70

80

90

100

110

120

130

140

150

160

4Q18 1Q19 2Q19

MNRL Peer 1 Peer 2

Value of DiversificationDiversified Core Minerals

Peers: VNOM and FLMN.

MNRL’s Diversified Portfolio Generates Peer Leading Growth with Price Stability

Realized Oil PricesDaily Production Growth Indexed to 100

Less Impacted by Basin Specific Basis BlowoutsStrong Growth from all Basins

Page 8MNRL

$-

$30

$60

$90

$120

0

1,600

3,200

4,800

6,400

WILLISTON DJ STACK SCOOP MIDLAND DELAWARE WTI PRICE

Boe/d $ WTI

WTI

Pro Forma Production Growth Lookback54% Pro Forma Production CAGR Over 6+ Years

Assuming the current portfolio was acquired on January 1, 2013, production from Brigham Minerals’ current

position would have yielded a 54% compound annual growth rate over the last 6+ years(1)

(1) Beginning January 1, 2013 through March 31, 2019.

Delaware 67%

DJ 76%

Midland 140%

SCOOP 36%

STACK 46%

Williston 33%

TOTAL 54%

6+ Year CAGR

Page 9MNRL

25 31

51

64

73

62

-

1,500

3,000

4,500

6,000

-

25

50

75

100

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

Other Williston DJ Basin STACK

SCOOP Midland Delaware NRA

Rigs NRA

2,352

3,881

4,579

5,382

6,768

-

2,000

4,000

6,000

8,000

2017 2018 4Q18 1Q19 2Q19

Daily Production

Production & RevenueDUC Inventory Provides Visibility to Continued Growth in 2019 & 2020

Boe/d Prior Period DUCs

Net Production and DUC Inventory

YE17

DUCs

497

2Q 2019 DUC inventory and current rig activity provides

visible foundation for continued 2019 and 2020 Growth

Average Quarterly Rigs and NRA Under Development

YE18

DUCs

808

YE18

DUCs

808

1Q19

DUCs

860

2Q19

DUCs

943

Source: Company filings and RSEG.

Note: DUC inventory from the 2Q 2019 Internal Reserves.

Page 10MNRL

-

20

40

60

80

100

0

100

200

300

400

500

2012 2013 2014 2015 2016 2017 2018 YTD19

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

~1,440

Deals~74,100

NRA

Page 11MNRL

0

1

2

3

4

5

6

7

Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

Lower 48 Royalty Owners (20% NRI) Total Public Royalty Production

Significant Acquisition PotentialMineral Ownership is Highly Fragmented

Gross Core Delaware Acres Total US Royalty Production

MNRL Current NMA: 13,500

Potential Gross Core Acres: ~2,900,000(1)

Only <2% of royalties

owned by Public US Royalty Companies(2)

MMboe/d

Public US Royalty companies produced

~100 Mboe/d in 2Q19(3)

(1) Company estimates of total gross core acres in basin based on map outline.

(2) Total Royalty Production based on assumed 20% Royalty of EIA Production as of April 30, 2019.

(3) Production total includes BSM, KRP, FLMN and VNOM.

Huge Opportunity to Continue to Acquire in the Core

Total Royalty Production Estimated at

6 MMboe/d in 2Q19(2)

Note: Data as of August 2019.

Page 12Page 12MNRL

Portfolio Overview

Page 13MNRL

Note: Includes only Horizontal Locations.

(1) Includes Extended Woodford, Merge and Marcellus.

(2) Product mix displayed for 2Q19.

(3) 3P wells per DSU from YE18 Reserve Report.

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

NRA / % of Total 21,750 / 29% 3,500 / 5% 10,250 / 14% 10,050 / 14% 15,450 / 21% 6,900 / 9% 74,100 / 100%

2Q19 Production / % of Total 2,606 / 39% 304 / 4% 645 / 10% 1,136 / 17% 1,191 / 18% 764 / 11% 6,768 / 100%

Production by Product (2)

Gross / Net DUCs 261 / 2.1 44 / 0.2 128 / 0.8 78 / 0.5 218 / 1.2 187 / 0.4 943 / 5.3

Gross / Net Permits 154 / 0.8 67 / 0.3 25 / 0.1 27 / 0.1 196 / 2.1 195 / 0.3 680 / 3.6

3P Wells per DSU(3)

2Q19 Avg Rigs Running 26 3 13 6 5 9 62

Top Operators

Portfolio Area OverviewCore Position in Premier Liquids-Rich Basins

Oil58%NGL

18%

Gas24%

Oil72%

NGL11%

Gas17%

Oil56%

NGL9%

Gas35%

Oil39%

NGL23%

Gas38%

Oil56%

NGL9%

Gas35%

Oil79%

NGL11%

Gas10%

Oil56%

NGL15%

Gas29%

PD / DSU4.6

Undev / DSU4.7

PD / DSU5.4

Undev / DSU9.1

PD / DSU1.7

Undev / DSU10.6

PD / DSU2.2

Undev / DSU6.6

PD / DSU2.0

Undev / DSU10.9

PD / DSU2.0

Undev / DSU12.5

14.53P/DSU

12.93P/DSU

8.83P/DSU

12.23P/DSU

14.53P/DSU

9.33P/DSU

PD / DSU3.0

Undev / DSU8.5

11.53P/DSU

Page 14MNRL

PD / DSU4.6

Undev / DSU4.7

PD / DSU1.7

Undev / DSU10.6

PD / DSU2.0

Undev / DSU10.9

14.53P/DSU

PD / DSU5.4

Undev / DSU9.1

PD / DSU2.2

Undev / DSU6.6

PD / DSU2.0

Undev / DSU12.5

8%

13%

13%

15%

9%7%

35%

Undeveloped Locations

Delaware

Midland

SCOOP

STACK

DJ

Williston

Other¹4,779

12,085

16,864

Inventory

3P (72%)

PD (28%)

Undeveloped Gross LocationsTotal Gross Locations

Source: 2Q 2019 Internal Reserves. Spacing data as of December 31, 2018.(1) Other includes Extended Woodford, Merge and Marcellus.

(2) Inventory life calculated as 3P undeveloped locations divided by annualized 2Q19 spuds.

13 Years of

Inventory

Life(2)

Substantial Organic Inventory81% Undeveloped in the Permian and SCOOP/STACK

Williston Wells per DSU

Delaware Wells per DSU SCOOP Wells per DSU DJ Wells per DSU

Midland Wells per DSU STACK Wells per DSU

12.93P/DSU

12.23P/DSU

9.33P/DSU

PD / DSU Undev / DSU

Midland Wells per DSU STACK Wells per DSU

14.53P/DSU

8.83P/DSU

Page 15MNRL

5.6

1.6

1.2

5.4

16.0

8.4

8.3

5.7

2.4

1.0

2.4

1.6

1.6

3.8

0.5

2.3

4.4

11.4

21.0

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

Delaware Midland SCOOP STACK DJ Williston Other

960

849

716

416

1,212

950

848

779

286

112

314

204

202

302

144

386

612

1,024

1,769

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

Delaware Midland SCOOP STACK DJ Williston Other

100% Net Horizontal Well Locations – (104.4)Gross Horizontal Well Locations - (12,085)

7%

9%

13%

13%

35%

48% of Net Locations in Permian and 35% of Net Locations are Wolfcamp

Source: 2Q 2019 Internal Reserves.

Organic Undeveloped Inventory

8%

15%

6%

8%

20%

3%

42%

5%

16%

Page 16Page 16MNRL

Portfolio Area Highlights

Page 17MNRL

Other5%

Avalon1% 1st Bone Spring

4%

2nd Bone Spring5%

3rd BS / WC XY10%

Wolfcamp B26%

Wolfcamp A49%

MNRL DSUs

Delaware Basin OverviewCore Outline Validated by Operator Rig Activity

Delaware

21,750

NRAs

Key Operators

Net Well Locations

Net Royalty Acres

43.4

Net Wells

MNRL Core Outline 4,237 gross wells12,085 gross wells

Loving County

Development Area

Source: Public Data, DrillingInfo and IHS.

Note: Map data as of July 27, 2019. Well locations as of 6/30/2019.

104.4

Net Wells

MNRL DSU Acreage

Active Rig

Delaware42%

Midland6%

SCOOP8%

STACK16%

DJ20%

Williston3%

Other5%

Page 18MNRL

Delaware29%

Midland5%

SCOOP14%

STACK14%

DJ21%

Williston9%

Other8%

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

MNRL Core Outline

SpringBoard

Development Area

SCOOP

10,250

NRAs

Key Operators

Net Royalty Acres

8.1

Net Wells

1,065 gross wells

Net Well Locations

12,085 gross wells

MNRL DSUs

104.4

Net Wells



MNRL DSU Acreage

Active Rig

Woodford71%

Springer29%

Delaware42%

Midland6%

SCOOP8%

STACK16%DJ

20%

Williston3%

Other5%

Page 19MNRL

Large Scale DevelopmentUnderpinned by Proven Operators

37 DUCs, 6 Rigs and 19 Permits highlight significant

near-term development

Source: Company Estimates and Public Data.

MNRL Acreage

Producing

Permit

Active Rig

Loving County Development Area OXY / XTO / EOG CLR Project SpringBoard

In 30 of 31 DSUs, CLR drilling ~ 350 Springer,

Woodford and Sycamore wells

1 Mi 1 Mi

Page 20Page 20MNRL

Financial Overview

Page 21MNRL

$8.2 $9.4

$8.4 $7.4

$4.2

($3.2)

$(10)

$(5)

$-

$5

$10

$15

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

$10.8

$13.8 $15.5

$13.0 $13.8

$18.3

$-

$5

$10

$15

$20

$25

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

76%82% 83%

74% 76% 74%

0%

20%

40%

60%

80%

100%

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

Quarterly Financial Results

Total Revenue and Realized Price

Net Income

Adjusted EBITDA(1)

Adjusted EBITDA Margin(1)(2)

$ in MM and $ / Boe $ in MM

(1) Please see Appendix for a reconciliation of Adjusted EBITDA to net income (loss), the Company's most directly comparable financial measure calculated in accordance with GAAP.

(2) Adjusted EBITDA divided by total revenue.

(3) Please see Appendix for a reconciliation of Adjusted net income (loss) to net income (loss), the Company's most directly comparable financial measure calculated in accordance with GAAP.

$ 21

CAGR

42%

Rev.

CAGR

45%

2Q Adj.

Net

Income

$3.7 (3)

Page 22MNRL

0% of PSU at <10% ATSR

100% of PSU at 15% ATSR

$83

$120

$203

Total Liquidity - June 30, 2019

Borrowing Base - June 30, 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):

▪ 50% Restricted Stock Units (“RSU”) and 50% Performance-based restricted stock units (“PSUs”)

❑ RSUs vest 1/3 per year

❑ PSU - absolute total shareholder return (“ATSR”) focus for management incentives / cliff vest at end of year 3

❑ Target 3 year annualized return of 15% yields 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 / EBITDA

❑ Acquisitions to be funded through a mix of equity and debt

❑ Minimal existing hedges with little to no hedging going forward

PSUs - ATSR Hurdles

Page 23MNRL

Quarterly Dividend

❑ Declared first quarterly dividend of $0.33 per share of Class A common stock

▪ Based on results for full quarter beginning April 1, 2019

o Not prorated for April 23, 2019 IPO date

❑ Dividend to be paid on August 29, 2019 to holders of record as of August 22, 2019

❑ MNRL anticipates distributing substantially all discretionary cash flow for the remainder of 2019

(1) Please see Appendix for a reconciliation of Adjusted EBITDA to net income (loss), the Company's most directly comparable financial measure calculated in accordance with GAAP.

(in thousands) Three Months Ended

Jun. 30, 2019

Adjusted EBITDA(1) 18,289

Less:

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

Adjusted EBITDA attributable to Class A Common Stock $7,923

Less:

Cash Interest expense 550

Cash taxes 117

Dividend Equivalent Rights –

Retained Cash Flow –

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

Shares of Class A Common Stock 21,997

Discretionary cash flow available per share of Class A Common Stock $ 0.33

Page 24MNRL

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 Near-Term Production Growth

Page 25Page 25MNRL

Appendix

Page 26MNRL

Delaware29%

Midland5% SCOOP

14%

STACK14%

DJ21%

Williston9%

Other8%

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

MNRL Core Outline

STACK

10,050

NRAs

Key Operators

Net Royalty Acres

1,798 gross wells

Net Well Locations

12,085 gross wells

MNRL DSUs

16.7

Net Wells

104.4

Net Wells



MNRL DSU Acreage

Active Rig

Woodford50%

Meramec50%

Delaware42%

Midland6%

SCOOP8%

STACK16%

DJ20%Williston

3%

Other5%

Page 27MNRL

Delaware29%

Midland5%

SCOOP14%

STACK14%

DJ21%

Williston9%Other

8%

Codell25%

Niobrara75%

DJ Basin OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

Laramie

East

Pony

Wattenberg

DJ

15,450

NRAs

Key Operators

Net Royalty Acres

1,628 gross wells

Net Well Locations

12,085 gross wells

MNRL DSUs

21.3

Net Wells

104.4

Net Wells



MNRL DSU Acreage

Active Rig

Delaware42%

Midland6%

SCOOP8%

STACK16%

DJ20%

Williston3%

Other5%

Page 28MNRL

Delaware29%

Midland5%

SCOOP14%

STACK14%

DJ21%

Williston9%

Other8%

Midland Basin OverviewCore Outline Validated by Operator Rig Activity

Midland

3,500

NRAs

Key Operators

Net Royalty Acres

832 gross wells

Net Well Locations

12,085 gross wells

MNRL Core Outline

MNRL DSUs

6.5

Net Wells

104.4

Net Wells



MNRL DSU Acreage

Active Rig

Other15%

Lower Spraberry

36%Wolfcamp B

25%

Wolfcamp A24%

Delaware42%

Midland6%

SCOOP8%

STACK16%

DJ20%

Williston3%

Other5%

Page 29MNRL

Delaware29%

Midland5%

SCOOP14%

STACK14% DJ

21%

Williston9%

Other8%

Williston Basin OverviewCore Outline Validated by Operator Rig Activity

MNRL Core Outline

Williston

6,900

NRAs

Key Operators

Net Royalty Acres

1,565 gross wells

Net Well Locations

12,085 gross wells

MNRL DSUs

2.7

Net Wells

104.4

Net Wells



MNRL DSU Acreage

Active Rig

Three Forks58%

Bakken42%

Delaware42%

Midland6%

SCOOP8%

STACK16%

DJ20%

Williston3%

Other5%

Page 30MNRL

Weighted Imlied Average

Net Avg. Net 100% Gross Net Revenue

Mineral Acres Royalty Royalty Acres (1) Royalty Acres (2) DSU Acres Interest Per Well (3)

Delaware 13,500 20% 21,750 2,700 265,000 1.0%

Midland 2,900 15% 3,500 450 64,000 0.7%

SCOOP 6,900 19% 10,250 1,300 184,000 0.7%

STACK 7,100 18% 10,050 1,250 165,000 0.8%

DJ 12,100 16% 15,450 1,950 167,000 1.2%

Williston 5,300 16% 6,900 850 475,000 0.2%

Other 4,100 19% 6,200 750 119,000 0.6%

TOTAL 51,900 18% 74,100 9,250 1,439,000 0.6%

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

◼ 51,900

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

◼ 74,100 = 51,900 * (18%) / (1/8)

◼ Net mineral acres * Avg. royalty

◼ 9,250 = 51,900 * 18%

◼ Total number of gross DSU acres

◼ 1,439,000

◼ 100% Royalty acres / Gross DSU acres

◼ 0.6% = 9,250 / 1,439,000

Note: As of June 30, 2019.

(1) Standardized to 1/8 royalty.

(2) Standardized to 100% royalty.

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

Page 31MNRL

($ in thousands) Three Months Ended

Jun. 30, Mar. 31, Jun. 30,

2019 2019 2018 2018 2017

Production:

Daily production (Boe/d) 6,768 5,382 3,723 3,881 2,352

% Liquids 71% 70% 70% 71% 66%

0 0Revenue:

Royalty revenue $23,049 $17,590 $14,522 $59,758 $30,066

Lease bonus and other revenue 1,480 675 2,367 7,506 10,842

Total revenue $24,529 $18,265 $16,889 $67,264 $40,9080.0 0.0

Other operating income:

Gain (loss) on sale of oil and gas properties, net – – – – 94,5510.0 0.0

Operating expense:

Gathering, transportation and marketing $1,523 $1,114 $912 $3,944 $1,754

Severance and ad valorem taxes 1,450 1,379 882 3,536 1,601

Depreciation, depletion and amortization 6,760 5,116 3,213 13,915 6,955

General and administrative 9,762 1,949 1,318 6,638 3,935

Total operating expense 19,495 9,558 6,325 28,033 14,245

0.0 0.0Operating income $5,034 $8,707 $10,564 $39,231 $121,214

0.0Other income (expense):

Gain (Loss) on derivative instruments, net $73 ($685) ($555) $424 ($121)

Interest expense, net (1,270) (3,825) (652) (7,446) (556)

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

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

Other income, net 6 29 6 110 305

0.0Income before taxes ($3,090) $4,226 $9,363 $33,142 $116,620

Tax expense (benefit) 117 190 12 (220) 1,008

Net income (loss) ($3,207) $4,036 $9,351 $33,362 $115,612

0.0Less: net income attributable to predecessor (1,590) (4,036) (9,351) (33,362) (115,612)

Less: net income attributable to temporary equity 2,941 – – – –

Net income (loss) attributable to Brigham Minerals, Inc. ($1,856) $– $– $– $–

Other Financial Data:

Adjusted Net Income $3,726 $4,036 $9,351 $33,362 $115,612

Adjusted EBITDA 18,289 13,823 13,777 53,146 33,618

Adjusted EBITDA ex lease bonus 16,809 13,148 11,410 45,640 22,7760.0 11,410.0

Balance Sheet Data:

Cash and cash equivalents $82,727 $8,564 $1,590 $31,985 $6,886

Total assets 677,642 567,152 435,507 554,026 334,477

Credit facilities – 180,894 70,000 170,705 27,000

Total liabilities 7,224 185,405 74,702 176,474 32,303

Total equity 58,456 381,747 360,805 377,552 302,174

Temporary equity 611,962 – – – –

Year Ended December 31,

Historical Financial Summary

Page 32MNRL

(in thousands) Three Months Ended

Jun. 30, Mar. 31, Jun. 30, Year Ended December 31,

2019 2019 2018 2018 2017

Net income ($3,207) $4,036 $9,351 $33,362 $115,612

Add:

Loss on extinguishment of debt 6,933 – – – –

Adjusted net income $3,726 $4,036 $9,351 $33,362 $115,612

Add:

Depreciation, depletion and amortization 6,760 5,116 3,213 13,915 6,955

Interest expense, net 1,270 3,825 652 7,446 556

Share based compensation expense 6,495 – –

(Gain) / Loss on sale of distribution of equity securities – 685 – – 4,222

Loss on commodity derivative instruments, net – – 555 – 121

Income tax expense 117 190 12 – 1,008

Less:

Gain on derivative instruments, net 73 – – 424 –

Other income, net 6 29 6 110 305

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

Gain on distribution of equity securities – – – 823 –

Income tax benefit – – – 220 –

Adjusted EBITDA $18,289 $13,823 $13,777 $53,146 $33,618

Less:

Lease bonus 1,480 675 2,367 7,506 10,842

Adjusted EBITDA ex lease bonus $16,809 $13,148 $11,410 $45,640 $22,776

Adjusted EBITDA $18,289 $13,823 $13,777 $53,146 $33,618

Less:

EBITDA attributable to Non Controlling Interest (10,366) – – – –

EBITDA attributable to Class A Common Stock $7,923 – – – –

Less:

Cash interest expense 550 – – – –

Cash taxes 117 – – – –

Dividend Equivalent Rights – – – – –

Retained Cash Flow – – – – –

Discretionary cash flow available to Class A Common Stock $7,256 $– $– $– $–

Non-GAAP Reconciliations

Page 33MNRL

DUCs70%

Permits1%

Acquired29%

301 Wells

Converted to

PDP

Location Conversion

PDP Conversion

DUC Conversion

90% of DUCs

Less than One year old

24% of Gross DUCs converted to PDP and generating ~115 new permits per month

860

(209)

292 943

2Q19 Investor Presentation...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

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