Q2 2020 Investor Presentation August 2020 Disclaimer The financial - - PowerPoint PPT Presentation

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Q2 2020 Investor Presentation August 2020 Disclaimer The financial - - PowerPoint PPT Presentation

Q2 2020 Investor Presentation August 2020 Disclaimer The financial projections and other estimates contained herein are forward-looking statements with respect to the anticipated pe rformance of Brigham Minerals, Inc. and its affiliates


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Q2 2020 Investor Presentation

August 2020

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MNRL

Disclaimer

The 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,

  • perational 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

  • f 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

  • ver 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

  • r 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.

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MNRL

High operating margins

Differentiated Positioning

Strength 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

  • perating 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.

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MNRL

3.9x 2.5x 1.8x 1.1x <0.0x 0.0x 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 Sheet

MNRL 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)

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MNRL

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

OXY 12% CVX 8% OVV 6% CLR 5% MRO 4% XEC 4% DVN 4% XOM 4% EOG 3% FANG 3% PRI 3% CPE 3% RDS 3% PXD 3% WLL 2% PDCE 2% PE 2% XOG 2% Camino 2% CXO 2% Other Public 8% Other Private 14%

~125 total

  • perators

Operator Exposure by NRI (3)(4)

Brigham Minerals Overview

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

Oil 50% Gas 29% NGL 21%

Delaware Midland SCOOP/STACK Williston DJ

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MNRL 82 99 208 150 230 248 214 185 209 36 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 Update

Inventory 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

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MNRL 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 Converted Permitted Converted Unpermitted 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 to PDP Acquired Wells Converted Permit Converted Unpermitted Other Q2 2020 DUCs 882 705 (222) 6 29 7 3 250 500 750 1,000 Q1 2020 DUCs Converted to PDP Acquired Wells Converted Permit Converted Unpermitted Other Q2 2020 DUCs 5,234 5,444 7 222 19 3,000 3,750 4,500 5,250 6,000 Q1 2020 PDP Acquired Wells Converted DUC Converted Permitted Converted Unpermitted Other Q2 2020 PDP

Location Conversion

MNRL 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

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MNRL

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 Total

4,653 / 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

Oil 50% Gas 29% NGL 21% Oil 52% Gas 21% NGL 27% Oil 42% Gas 46% NGL 12% Oil 29% Gas 44% NGL 27% Oil 36% Gas 49% NGL 15% Oil 70% Gas 9% NGL 21% Oil 58% Gas 20% NGL 22%

Portfolio Area Overview

Core Position in Premier Liquids-Rich Basins

14.3

3P/DSU

15.0

3P/DSU

9.0

3P/DSU

11.5

3P/DSU

15.3

3P/DSU

9.5

3P/DSU

11.8

3P/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.

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MNRL

394 373 388 199 125 78 47 43 14 9 51 40 37 11 5 51 45 45 18 10

100 200 300 400 500 600 700 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Current Permian Anadarko Niobrara Bakken

110 100 89 22 35 21 10 12 2 3 19 19 10 3 20 19 16 2 4

30 60 90 120 150 180 210 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Current Permian Anadarko Niobrara Bakken

Disciplined Acquisition Strategy

Targeting 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

  • perators

Focusing on operators with the lowest cost inventory Location Seeking low cost per net location and an

  • ptimized 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.

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MNRL 6% DUCs & Permits

PDP 21% DUCs 3% Permits 3% Unpermitted 73%

7% DUCs & Permits

PDP 21% DUCs 4% Permits 3% Unpermitted 72%

7% DUCs & Permits

PDP 21% DUCs 4% Permits 3% Unpermitted 72%

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 Summary

Q2 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% Q4 2019 Acquisitions $7.2 M / 19% Q1 2020 Acquisitions $6.7 M / 7% Q2 2020 Acquisitions $4.2 M / 7%

  • 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.

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MNRL

MNRL DSUs

Delaware Basin Q3 2020 Acquisitions

Ground 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

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MNRL

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

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MNRL

Portfolio Overview & Highlights

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MNRL

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

9.0

3P/DSU

Undeveloped Gross Locations Total 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 Inventory

47% 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

11.5

3P/DSU

15.3

3P/DSU

9.5

3P/DSU

PD / DSU Undev / DSU

STACK Wells per DSU DJ Wells per DSU

14.3

3P/DSU

15.0

3P/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

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MNRL

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 Inventory

20 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%

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MNRL

Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

MNRL DSUs

Delaware Basin Overview

Core 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 wells 12,907 gross wells

Loving County Development Area 113.2 Net Wells

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

MNRL DSU Acreage Active Rig

Wolfcamp A 44% Wolfcamp B 25% 3rd BS / WC XY 12% 2nd Bone Spring 7% Avalon 1% Other 11% Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6%

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MNRL

Financial Overview

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MNRL

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

1

Borrowing 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

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

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MNRL ❑ 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)

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MNRL

Appendix

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MNRL

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.

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$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

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(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.

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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

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Midland Basin Overview

Core Outline Validated by Operator Rig Activity

Midland 4,800 NRAs

Key Operators Net Royalty Acres

1,230 gross wells

Undeveloped Well Locations

12,907 gross wells

MNRL Core Outline

MNRL DSUs

8.6 Net Wells 113.2 Net Wells

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

MNRL DSU Acreage Active Rig

Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6% Wolfcamp A 28% Wolfcamp B 26% Lower Spraberry 35% Other 11%

Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

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Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

DJ Basin Overview

Core 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

Undeveloped Well Locations

12,907 gross wells

MNRL DSUs

19.7 Net Wells 113.2 Net Wells

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

MNRL DSU Acreage Active Rig

Niobrara 75% Codell 25% Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6%

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Anadarko Basin (SCOOP) Overview

Core 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

Undeveloped Well Locations

12,907 gross wells

MNRL DSUs

113.2 Net Wells

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

MNRL DSU Acreage Active Rig

Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6%

Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

Springer 27% Woodford 73%

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Anadarko Basin (STACK) Overview

Core Outline Validated by Operator Rig Activity

MNRL Core Outline

STACK 10,700 NRAs

Key Operators Net Royalty Acres

1,748 gross wells

Undeveloped Well Locations

12,907 gross wells

MNRL DSUs

15.6 Net Wells 113.2 Net Wells

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

MNRL DSU Acreage Active Rig

Meramec 45% Woodford 55% Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6%

Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

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Delaware 32% Midland 6% SCOOP 13% STACK 13% DJ 19% Williston 9% Other 8%

Williston Basin Overview

Core Outline Validated by Operator Rig Activity

MNRL Core Outline

Williston 7,825 NRAs

Key Operators Net Royalty Acres

1,516 gross wells

Undeveloped Well Locations

12,907 gross wells

MNRL DSUs

3.0 Net Wells 113.2 Net Wells

MNRL DSU Acreage Active Rig

Source: Public Data, DrillingInfo and IHS. Note: Asset data as of June 30, 2020.

Bakken 43% Three Forks 57% Delaware 45% Midland 8% SCOOP 7% STACK 14% DJ 17% Williston 3% Other 6%