KRP Investor Presentationkimbellrp.investorroom.com/download/Winter+2019+Investor+Prese… · 33% of Q3’19 production is from EOR units and conventional fields with shallow declines

CONFIDENTIAL | NOT FOR DISTRIBUTION

WINTER 2019 INVESTOR PRESENTATION

2

DisclaimerThis presentation includes forward-looking statements relating to the business, financial performance, results, plans, objectives and expectations of Kimbell RoyaltyPartners, LP (“KRP” or “Kimbell”). Statements that do not describe historical or current facts, including statements about beliefs and expectations and statements about thefederal income tax treatment of future earnings and distributions, Kimbell’s business, prospects for growth and acquisitions, and the securities markets generally areforward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similarexpressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. Except as required by law, KRP undertakes no obligation anddoes not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in KRP’s filings with the Securities and Exchange Commission (“SEC”). Theseinclude risks inherent in oil and natural gas drilling and production activities, including risks with respect to low or declining prices for oil and natural gas that could result indownward revisions to the value of proved reserves or otherwise cause operators to delay or suspend planned drilling and completion operations or reduce productionlevels, which would adversely impact cash flow; risks relating to the impairment of oil and natural gas properties; risks relating to the availability of capital to fund drillingoperations that can be adversely affected by adverse drilling results, production declines and declines in oil and natural gas prices; risks regarding Kimbell’s ability to meetfinancial covenants under its credit agreement or its ability to obtain amendments or waivers to effect such compliance; risks relating to KRP’s hedging activities; risks of fire,explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks, which maytemporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales orcompletion of drilling operations; risks relating to delays in receipt of drilling permits; risks relating to unexpected adverse developments in the status of properties; risksrelating to borrowing base redeterminations by Kimbell’s lenders; risks relating to the absence or delay in receipt of government approvals or third-party consents; risksrelated to acquisitions, dispositions and drop downs of assets; risks relating to Kimbell's ability to realize the anticipated benefits from and to integrate acquired assets; andother risks described in KRP’s Annual Report on Form 10-K and other filings with the SEC, available at the SEC’s website at www.sec.gov. You are cautioned not to placeundue reliance on these forward-looking statements, which speak only as of the date of this presentation.

This presentation includes financial measures that are not presented in accordance with U.S. generally accepted accounting principles (“GAAP”), including ConsolidatedAdjusted EBITDA, and distributable cash flow (“DCF”). KRP believes Consolidated Adjusted EBITDA is useful because it allows management to more effectively evaluateKRP’s operating performance and compare the results of KRP’s operations period to period without regard to KRP’s financing methods or capital structure. In addition,KRP’s management uses Consolidated Adjusted EBITDA to evaluate cash flow available to pay distributions to its unitholders. KRP defines Consolidated Adjusted EBITDAas net income (loss), net of non-cash unit-based compensation, change in fair value of open commodity derivative instruments, impairment of oil and natural gas properties,income taxes, interest expense and depreciation and depletion expense. KRP excludes the foregoing items from net income (loss) in arriving at Consolidated AdjustedEBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets,capital structures and the method by which the assets were acquired. Certain items excluded from Consolidated Adjusted EBITDA are significant components inunderstanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets,none of which are components of Consolidated Adjusted EBITDA. KRP believes DCF is a useful standard to assist in evaluating its ability to make quarterly cashdistributions. KRP defines distributable cash flow as Consolidated Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations,fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate.

Consolidated Adjusted EBITDA and DCF are not measures of net income (loss) or net cash provided by operating activities as determined by GAAP. Consolidated AdjustedEBITDA and DCF should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues or any other measure of financial performance orliquidity presented in accordance with GAAP. You should not consider Consolidated Adjusted EBITDA or DCF in isolation or as a substitute for an analysis of KRP’s resultsas reported under GAAP. Because Consolidated Adjusted EBITDA and DCF may be defined differently by other companies in KRP’s industry, KRP’s computations ofConsolidated Adjusted EBITDA and DCF may not be comparable to other similarly titled measures of other companies, thereby diminishing their utility.

This presentation is for informational purposes only and shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale ofsecurities in any jurisdiction in which the offer, solicitation or sale would be unlawful prior to the registration or qualification under the securities laws of any such jurisdiction.No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933.

3

Table of Contents

Section I Company Overview and History

Section II Detailed Asset Overview

Section III Mineral Market Opportunity

4

Section I – Company Overview and History

5

12,785 Boe/d

Permian12%

Haynesville23%

Appalachia14%

Bakken4%

Eagle Ford11%

Rockies4%

82 Rigs

Company Overview Q3’19 Combined Production from the Most Economic Areas (Boe/d)(9)

Kimbell Overview

Royalty interests in over 92,000 wells across 13 million gross acres (approximately 144,100 net royalty acres) in the lower 48, with significant positions in some of the highest growth basins

No material federal income taxes expected for seven years. Substantially all distributions not expected to be taxable dividend income for next four years. Less than 25% of distributions expected to be taxable for subsequent three years(1)

Leading consolidator in highly fragmented oil and gas royalty space – completed approximately $700mm in accretive acquisitions between July 2018 and March 2019

Liquids-focused with approximately 64% of royalty revenues from oil and NGLs(2)

82 rigs drilling on Kimbell acreage at no cost to the company(3)

Best-in-class PDP decline rate of approximately 12%(4)

33% of Q3’19 production is from enhanced oil recovery (“EOR”) units and conventional fields with shallow declines

Active Rigs on Acreage by Basin(3)Capitalization Table

(1) See page 9 of this presentation for information concerning the assumptions and estimates underlying the expected tax treatment of distributions.(2) Q3’19 Kimbell oil, natural gas and NGL revenues are derived from a product mix of 57% oil, 7% NGL and 36% natural gas.(3) Rig count as of 9/30/2019.(4) Estimated 5-Year PDP average decline rate on a 6:1 basis.(5) A Class B unit is exchangeable together with a common unit of Kimbell’s operating company for a KRP common unit.

(6) Closing unit price as of 10/30/2019.(7) Net debt as of 9/30/2019.(8) Reflects the annualized Q3’19 distribution.(9) Shown on a 6:1 basis. Q3’19 run-rate average daily production excludes prior period production

recognized in Q3’19.

Permian38%

Mid-Continent16%

Haynesville18%

Appalachia2%

Bakken15%

Eagle Ford5%

Rockies6%

Other20%

Mid-Continent12%

Common Units Outstanding 23,520,219Class B Units Outstanding(5) 23,388,258

Total Units Outstanding 46,908,477

Unit Price(6) $14.14Market Capitalization $663,285,865

Net Debt(7) $70,963,495Series A Convertible Preferred Units 110,000,000

Enterprise Value $844,249,360

Tax Status: 1099-DIV/ No K-1Yield(8) 11.9%

6

192 companies

83 companies

Source: Capital IQ as of 10/30/2019.(1) Dividend yield is defined as a company’s most recent quarterly distribution annualized divided by such company’s current share price.(2) Leverage ratio is defined as a company’s total debt divided by such company’s LTM EBITDA.(3) See page 9 of this presentation for information concerning the assumptions and estimates underlying the expected tax treatment of distributions.

Superior Value Proposition

9 companies

Dividend Yield(1)

>10%

Market Cap>$500 million

Leverage Ratio(2)

<2.0x

Expected Tax Deferred Dividend(3)

NYSE + NASDAQ Publicly Traded Companies(5,542 companies)

Kimbell compares favorably on key traditional investment metrics to publicly traded companies across various industries

Offers superior combination of tax advantaged dividend yield with a strong balance sheet

Kimbell expects substantially all distributions will not be taxable

dividend income for the next four years (2019-2022). Distributions for 2023-2025 are expected to be

only 25% taxable.

7

Company Highlights

High-Quality Asset Base

Attractive Tax Structure(4)

Kimbell Positionedas a Natural Consolidator

Source: Company filings and Kimbell management(1) Acreage numbers include mineral interests and overriding royalty interests.(2) As of 9/30/2019.(3) Estimated 5-Year PDP average decline rate on a 6:1 basis.

Prudent Financial Philosophy

Net Royalty Acre position of approximately 144,100 acres(1) across multiple producing basins provides diversified scale

− Key basins include the Permian and Mid-Con where 44% of the Net Royalty Acres are located

~95% of all rigs in the Lower 48 are in counties where Kimbell holds mineral interest positions(2)

Best-in-class PDP decline rate of approximately 12%(3)

33% of Q3’19 production is from EOR units and conventional fields with shallow declines

− EOR production has been notably flat for the last twenty years (0.2% 20-Year CAGR)

Kimbell will continue to opportunistically target high-quality positions in the highly fragmented minerals arena

Kimbell can capitalize on weak IPO markets by providing an avenue for sponsors looking to exit minerals investments

Significant consolidation opportunity in the minerals industry, with over $550 billion in market size and limited public participants of scale

Kimbell targets long-term leverage of less than 1.5x

− Debt to Consolidated Adjusted EBITDA of 1.0x as of 9/30/2019(5)

Actively hedging for two years representing approximately 19% of current production

Insider ownership of 21.3% ensures shareholder alignment(6)

No material federal income taxes expected for the next seven years (less than 5% of distributable cash flow)

Substantially all distributions paid to common unitholders not expected to be taxable dividend income for the next four years (2019-2022)

Less than 25% of distributions to common unitholders expected to be taxable dividend income for subsequent three years (2023-2025)

Status as a C-Corp for tax purposes provides a more liquid and attractive security

Energy yield investor market has ~$6.0 trillion in assets under management, ~60x size of the MLP market

(4) See page 9 of this presentation for information concerning the assumptions and estimates underlying the expectedtax treatment of distributions.

(5) Consolidated Adjusted EBITDA is annualized (Q3’19 Consolidated Adjusted EBITDA multiplied by four).(6) Does not include Kimbell’s Series A preferred units on an as-converted basis.

8

Consistent Organic Growth over the Last 20 Years

(1) Reflects the compound annual growth rate attributable to Kimbell’s currently owned mineral and royalty interests as if it had acquired all of such interests on January 1, 1999.

7,000,000

8,500,000

10,000,000

11,500,000

13,000,000

14,500,000

16,000,000

17,500,000

19,000,000

100,000

300,000

500,000

700,000

900,000

1,100,000

1,300,000

1,500,000

1,700,000

1,900,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Oil

+ N

GLs

(BB

L)/Y

ear

Gas (M

CF)/Year

KRP Pro Forma Organic Net Production Growth (1999-2018)(1)

Oil & NGLs Gas

September 11, 2001

U.S. declares war on Iraq

OPEC fails to agree on cut

Global financial crisis

Time Frame Oil+NGLs Gas Total (6:1) Total (20:1)20-Year 3.7% 2.9% 3.2% 3.4%10-Year 6.6% 4.1% 5.0% 5.8%5-Year 3.7% 2.0% 2.7% 3.2%1-Year 11.2% (1.0%) 3.6% 7.1%

KRP Organic Growth

U.S. production reaches 10mm bbl/d

Kimbell’s assets have proven resilient through multiple commodityprice cycles and geopolitical events

9

On May 13, 2019, Kimbell announced the expected favorable federal income tax treatment of its future earnings and distributions paid to common unitholders for at least the next seven years

Expected Favorable Tax Treatment of Earnings and Distributions(1)

Kimbell expects that:

For the next seven years (2019 to 2025), the company will pay no material federal income taxes (less than 5% of estimated pre-tax distributable cash flow)

For the next four years (2019 to 2022), substantially all distributions paid to common unitholders will not be taxable dividend income

For 2023 through 2025, less than 25% of distributions paid to common unitholders will be taxable dividend income

Distributions in excess of the amount taxable as dividend income will reduce an investor's tax basis in its common units or produce capital gain to the extent such distributions exceed an investor's tax basis, and the reduced tax basis will increase an investor's capital gain when it sells its common units

(1) This expected favorable tax treatment is the result of certain non-cash expenses (principally depletion) substantially offsetting the company's taxable income and tax "earnings and profit.” The company's estimates of the tax treatment of company earnings and distributions are based upon assumptions regarding the capital structure and earnings of our operating company, the capital structure of the company and the amount of the earnings of our operating company allocated to the company. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which the company operates. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. Investors are encouraged to consult with their tax advisor on this matter.

We believe that this expected favorable federal income tax treatment will enhance the after-tax returns to Kimbell common unitholders

10

Active Rigs Drilling on Kimbell’s Acreage (as of 9/30/2019)

Kimbell has 82 active rigs (88% horizontal) drilling on our acreage at no cost to us

Permian

Well Name Operator County/State1 FULLERTON CLEARFORK UNIT-1815EXXON ANDREWS, TX2 NORTH DOLLARHIDE UNIT-514H OCCIDENTAL ANDREWS, TX3 GOLDSMITH LANDRETH/SAN AND KINDER MORGAN ECTOR, TX4 TATIA 0310-101H FIREBIRD ECTOR, TX5 SYCO UNIT-78 SABINAL GAINES, TX6 KOONCE SOUTH 46-3 UNIT 1-243 ENDEAVOR GLASSCOCK, TX7 LPI-DRIVER 33-28 (ALLOC-F)-6NU LAREDO GLASSCOCK, TX8 GARON 27-22-2AH SABALO HOWARD, TX9 CARTHEL 31-TTT-B02 WF-201H MATADOR LOVING, TX

10 YELLOW ROSE B UNIT-3H EOG LOVING, TX11 BESSIE 44-41 (ALLOC-1NH)-5LB GUIDON MARTIN, TX12 BESSIE 44-41 (ALLOC-1NH)-1LL GUIDON MARTIN, TX13 FRANCES 12-1-A-4402H PARSLEY MARTIN, TX14 PATRICIA UNIT 2-4816AH EXXON MARTIN, TX15 PATRICIA UNIT 2-4878JH EXXON MARTIN, TX16 PATRICIA UNIT 2-4806BH EXXON MARTIN, TX17 PATRICIA UNIT 2-4808BH EXXON MARTIN, TX18 ARICK-HOOPER UNIT-103H PIONEER MIDLAND, TX19 ARICK-HOOPER UNIT-5H PIONEER MIDLAND, TX20 GOLLADAY-8HB MURCHISON MIDLAND, TX21 HOGAN 1-13-C-4206H PARSLEY MIDLAND, TX22 RINGO 8-9-DZ-4108H PARSLEY REAGAN, TX23 ALLISON 36-54 ALLOC A-10 H CARRIZO REEVES, TX24 BLANCO A 224-223E-10H PRIMEXX REEVES, TX25 SACROC UNIT-92-13 KINDER MORGAN SCURRY, TX26 SUNTURA (LOWER CLEAR FORK) U GREAT TERRY, TX27 BROOK B-13B-8H PIONEER UPTON, TX28 G.W. O'BRIEN ET AL-4H BOSQUE WARD, TX29 UTL 2833-17-83H JAGGED PEAK WARD, TX30 W.E. BAIRD-1807 MECO IV WINKLER, TX31 ALLEY CAT 17 20 FEDERAL COM-52 DEVON LEA, NM

Haynesville

Well Name Operator County/State32 HA RA SU61;CHK 33-28-21 HC-003 AETHON BIENVILLE, LA33 HA RA SU67;ROY 18-19 HC-001 AETHON BOSSIER, LA34 HA RA SU69;TREAT 14-23 HC-003 AETHON BOSSIER, LA35 HA RA SUE;HEARNE 20-17 HC-002 COMSTOCK CADDO, LA36 HA RA SUE;QUERBES 20-17 HC-004 COMSTOCK CADDO, LA37 HA RA SUTT;AFP28&21&16-15-16H CHESAPEAKE CADDO, LA38 HA RA SUE;BEDSOLE 3-10 HC-002 COMSTOCK DESOTO, LA39 HA RA SUJ;BLUNT 10&3-12-15 HC INDIGO II DESOTO, LA40 HA RA SUN;LAND & KNOWLES 8-5 GEOSOUTHERN DESOTO, LA41 HA RA SUQ;PERKINS 3-10 HC-001 COMSTOCK DESOTO, LA42 SCRUGGS 10&3-12-15 H-001 INDIGO II DESOTO, LA43 CARTHAGE GAS UNIT-1H COMSTOCK PANOLA, TX44 WAGSTAFF-BECKVILLE-1HH SPONTE PANOLA, TX45 CHAPEL HILL 3 (ALLOCATION)-1H MAVERICK SMITH, TX46 CHAPEL HILL 6 (ALLOCATION)-1H MAVERICK SMITH, TX

Mid-Continent

Well Name Operator County/State47 COOLEY-4-24-25-36XHW CONTINENTAL GRADY, OK48 COOLEY-5-24-25-36XHW CONTINENTAL GRADY, OK49 COOLEY-3-24-25-36XHW CONTINENTAL GRADY, OK50 GALVIN-3-22-15XHW CONTINENTAL GRADY, OK51 JACQUEZ-2-18-19XHW CONTINENTAL GRADY, OK52 KIMBER 0707-17-20-1MH CAMINO NR GRADY, OK53 RUE 0606-2-22-15 WXH MARATHON GRADY, OK54 SPARKS-2-22-27-34XHW CONTINENTAL GRADY, OK55 UMBACH-8-21-28-33XHW CONTINENTAL GRADY, OK56 UMBACH-4-21-28-33XHW CONTINENTAL GRADY, OK57 YELLOW SUB 0605-35-2-4WHX WARWICK-JUPITERGRADY, OK58 FANNIE-3-1/12H TRINITY PITTSBURG, OK59 RALPH 0304-4-11-2WXH MARATHON GARVIN, OK

Bakken

Well Name Operator County/State60 CROSBY CREEK-4-5H SINCLAIR DUNN, ND61 MARINER-14X-36D EXXON DUNN, ND62 HA-NELSON A--152-95-3427H-8 HESS MCKENZIE, ND63 WOLD FEDERAL-44-1-3TFH WHITING MCKENZIE, ND64 EN-RULAND--156-94-3328H-4 HESS MOUNTRAIL, ND65 ETHAN 15-22-#3TFH KRAKEN III MOUNTRAIL, ND66 LINDSETH-11-1-2H WHITING MOUNTRAIL, ND67 LAVERN-42X-14BXC EXXON WILLIAMS, ND68 LINDA-41X-22H EXXON WILLIAMS, ND69 MARCIA 3-10-#8TFH EQUINOR WILLIAMS, ND70 OLAF-42X-11C EXXON WILLIAMS, ND71 TI-STENBAK--158-95-2526H-4 HESS WILLIAMS, ND

Rockies

Well Name Operator County/State72 COMBS 11-33-71 USA A-NB 4H CHESAPEAKE CONVERSE, WY73 CLAUSEN 7-34-70-USA A NB 2H CHESAPEAKE CONVERSE, WY74 CLAUSEN-12-34-71 USA B TR 7H CHESAPEAKE CONVERSE, WY75 STUD HORSE BUTTE-119-09 JONAH SUBLETTE, WY76 STUD HORSE BUTTE-28-14 JONAH SUBLETTE, WY

Eagle Ford

Well Name Operator County/State77 WILLIAM B-3H CHESAPEAKE BURLESON, TX78 STAG HUNTER-5H PENN VIRGINIA GONZALES, TX79 SLATOR RANCH-A 6 SMITH PROD WEBB, TX80 SLATOR RANCH-C 4 SMITH PROD ZAPATA, TX

Appalachia

Well Name Operator County/State81 BLUE BECK LTD-8H SWN SUSQUEHANNA, PA82 REIMILLER UNIT REIMILLER 11H-11HBKV WYOMING, PA

11

$0.23 $0.30

$0.31 $0.36

$0.42

$0.43 $0.45

$0.40 $0.37

$0.39 $0.42

1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19

Prior Cumulative Distributions Quarterly Distributions

3,116 3,067 3,297 3,508 3,650 3,633

8,546

10,066

11,958 11,807 12,785

1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19

Source: Company filings and presentations.(1) Shown on a 6:1 basis.(2) Q3’19 run-rate average daily production excludes prior period production of 2,053 Boe per day recognized in Q3’19.(3) Acreage numbers include mineral interests and overriding royalty interests.(4) Stub distribution from 2/8/2017 to 3/31/2017.

Kimbell’s Track Record Since IPOProduction Growth (Boe/d)(1) Net Royalty Acres(3)

Distribution Growth

We have returned ~23% of our $18.00/unit IPO price via cash dividends in just under three years

Cash G&A per Boe

(4)$0.23 $0.53 $0.84

$1.20$1.62

$2.05$2.50

$0.53$0.23

$0.84$1.20

$1.62$2.05

$2.50$2.90

$2.90

$3.66

$3.27

$3.27

62,992 69,807 69,807 71,336 71,276

115,256 115,256

131,909 144,117 144,117 144,117

1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19

$3.66

$4.08

$7.47 $7.33

$6.20 $6.99

$6.40 $6.32 $5.65

$4.50 $3.95 $3.82

$3.30

1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19

(2)

12

Section II – Detailed Asset Overview

13

Scale Across Lower 48

(1) Based on DrillingInfo rig count as of 9/30/2019.

13.0 million gross acres across 28 states and in every major producing basin~95% of all rigs in the Lower 48 are in counties where Kimbell holds mineral interests positions(1)

14

Kimbell’s Permian Position ~2.6 million gross and ~23,500 net royalty acres represent

approximately 20% and 16%, respectively, of Kimbell’s acreage portfolio

31 rigs operating on KRP’s Permian acreage

Q3’19 run-rate production of 1,561 Boe/d

− Represents 12% of Q3’19 run-rate production

− 63% conventional production, 37% unconventional production

~40,200 producing wells

Leading E&P operators on KRP’s acreage include:

Note: Q3’19 run-rate average daily production excludes prior period production recognized in Q3’19 and is shown on a 6:1 basis. Well count, acreage and rig count as of 9/30/2019.

15

Kimbell’s Mid-Continent Position ~3.6 million gross and ~40,600 net royalty acres represent


13 rigs operating on KRP’s Mid-Con acreage






Note: Q3’19 run-rate average daily production excludes prior period production recognized in Q3’19 and is shown on a 6:1 basis. Well count, acreage and rig count as of 9/30/2019. Data represents entire Mid-Con positionwhile map represents KRP’s Oklahoma position in the Mid-Continent.

16

Kimbell’s Haynesville Position ~745,700 gross and ~7,100 net royalty acres represent


15 rigs operating on KRP’s Haynesville acreage







17

Kimbell’s Appalachia Position ~721,700 gross and ~23,100 net royalty acres represent


2 rigs operating on KRP’s Appalachia acreage







18

Kimbell’s Eagle Ford Position ~532,100 gross and ~6,300 net royalty acres represent


4 rigs operating on KRP’s Eagle Ford acreage







19

Kimbell’s Bakken Position ~1.6 million gross and ~6,000 net royalty acres represent


12 rigs operating on KRP’s Bakken acreage

Q3’19 run-rate production of 500 Boe/d






20

74.1%

1.9%

24.0%25.9%

Kimbell has the Optimal Balance of Unconventional and Conventional Assets

Oil Gas

NGL

Conventional EOR Non-EORUnconventional

Conventional EOR Non-EORUnconventional Conventional EOR Non-EORUnconventional

Note: Graphs reflect Q3 2019 Production on a 6:1 basis.

Kimbell has approximately 33% of its overall production from conventional assets including certain Enhanced Oil Recovery (EOR) projects. This conventional production provides a base level of production stability that helps

facilitate overall organic production growth as new unconventional wells come online. In addition, EOR production has been notably flat over the last 20 years (0.2% 20-Year CAGR).

Total Production (Boe)

50.7% 29.4%19.9%49.3%

Conventional EOR Non-EORUnconventional

64.0%

9.1%

26.9%36.0% 66.6%

10.0%

23.4%33.4%

21

Jul-1

9

Sep-

19

Nov

-19

Jan-

20

Mar

-20

May

-20

Jul-2

0

Sep-

20

Nov

-20

Jan-

21

Mar

-21

May

-21

Jul-2

1

Sep-

21

Nov

-21

Jan-

22

Mar

-22

May

-22

Jul-2

2

Sep-

22

Nov

-22

Jan-

23

Mar

-23

May

-23

Jul-2

3

Sep-

23

Nov

-23

Jan-

24

Mar

-24

May

-24

5-Year

Unconventional Conventional - EOR Conventional - Non EOR Total

5-Year PDP Decline Forecast

6% Decline Rate(1)

Tota

l BO

EShallow decline rates from both its conventional and unconventional assets help to create Kimbell’s best-in-

class overall proved developed producing (PDP) decline rate of 12%. This is in contrast to many of the working interest companies and some mineral peers that have PDP decline rates of over 30%.

(1) Estimated 5-Year PDP average decline rate on a 6:1 basis.

22

Section III – Mineral Market Opportunity

23

Tremendous Consolidation Opportunity

Permian Basin Working Interest MarketNational Minerals Market

Total Public Company Enterprise Value(2):

2%Market Opportunity:

98%

Total Market Size(1): ~$550 billion Total Market Size(3): ~$270 billion

National minerals market is approximately 2x larger than the entire Permian working interest market with only 1/32nd of the public consolidation

(3) Market size calculated based on production data and strip pricing from EIA as of 3/1/19. Assumes an average royalty burden of20%. Also assumes a 64% average EBITDA margin and a 5.5x average EBITDA multiple per FactSet and derived from thefollowing companies: XEC, PE, WPX, CDEV, PDCE, JAG, MTDR, QEP, SM, CPE, LPI, CXO, OXY, FANG and PXD.

(4) Enterprise values of XEC, PE, WPX, CDEV, PDCE, JAG, MTDR, QEP, SM, CPE, LPI, CXO, OXY, FANG and PXD as of 3/1/19.

Source: EIA and FactSet.(1) Midpoint of market size estimate range. Based on production data from EIA as of 8/8/19 and average 2019 strip pricing.

Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 20%. Assumes a 10x multiple on cashflows to derive total market size.

(2) Enterprise values of KRP, BSM, FLMN, DMLP, MNRL and VNOM as of 9/30/19.

Total Public Company Enterprise Value(4):

63%

Market Opportunity:

37%

24

Highest Cash Flow Yield Across Multiple Sectors

Source: Capital IQ as of 10/29/2019. RoyaltyCo: Average of VNOM, BSM, FLMN, MNRL and KRP distribution yield; Midstream based on AMNA Index; Large-Cap E&Ps: Includes APA, COP, HES, MRO, MUR, NBL, OXY, DVN, ECA, COG; Integrateds: Includes CVX, XOM, CNQ, CVE, HSE, IMO, SU; Precious metal producers: Includes ABX (CA), AEM (CA), FCX, NEM, OR, RGLD, WPM.

Distribution/Dividend Yield Comparison

U.S. oil and gas royalty companies offer an attractive 9.2% yield versus the rest of the public space, including midstream companies, integrateds and large cap E&Ps. In addition, royalty companies offer far superior cash

yields as compared to the precious metals and REIT sectors as well as the S&P 500.

12.1%

9.2%

6.6%

3.9% 3.8% 3.1%1.9% 1.3%

RoyaltyCo's Midstream Integrateds MSCI REITIndex

Large-Cap E&P S&P 500 Precious MetalProducers

25

30.2%

22.4% 20.3% 19.0%

15.6% 13.8%

7.0% 4.9% 3.3% 3.0%

(2.8%)

(17.6%)

(39.3%)(45.0%)

(35.0%)

(25.0%)

(15.0%)

(5.0%)

5.0%

15.0%

25.0%

35.0%

Technology ConsumerDiscretionary

Utilities REITs Minerals Health Care ConsumerStaples

Industrials Financials CommunicationServices

Materials Energy Oil & Gas

Minerals have Outperformed Most Other Broad Sectors

Source: FactSet as of 10/29/2019.Note: All sectors except Minerals and Oil & Gas based on S&P 500 select sector indices. Minerals based on average total return of BSM, DMLP, MNRL, KRP, VNOM and FLMN where applicable. Oil & Gas based on XOP Oil & Gas E&P ETF.

Total Return by Sector (1/1/18 – Present)

In recent years, the minerals market has significantly outperformed manyother major sectors, especially oil and gas, in regards to total return

26

Kimbell’s Performance vs. Mineral Peers and the XOP Index

Source: Company filings and S&P Capital IQ.(1) Returns based on common equity price as of 1/1/2019, year-to-date distributions and common equity price as of 10/30/2019.(2) KRP returns based on unit price of $13.58 as of 1/1/2019, year-to-date distributions and unit price of $14.14 as of 10/30/2019. S&P Oil and Gas Index (XOP) returns based on XOP’s share price of $26.53 as of 1/1/2019, year-to-date distributions and XOP’s share

price of $21.23 as of 10/30/2019.

Total Return YTD 2019 – XOP Index(2)

1/1/19 4/12/19 7/21/19 10/30/19

16%

(19%)

Total Return YTD 2019 – Mineral Peers(1)

(40.0%)

(30.0%)

(20.0%)

(10.0%)

–

10.0%

20.0%

30.0%

40.0%

50.0%

Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19

15.8% KRP

(5.6%) BSM

1.5% VNOM

(24.6%) PSK(21.0%) FLMN

(0.5%) MNRL

KRP XOP

27

Production

Positive Revisions

Minerals are Subsurface Real Estate

Kimbell’s 5% organic proved developed producing (PDP) reserve growth is akin to adding additional floors to a subsurface building

PDP Reserves YE 2017

PDP Reserves YE 2018

82 active rigs drilling at no cost to Kimbell creates “additional floors” to subsurface building

Our real estate continues to grow and our ~12% yield is approximately 3x the yield of the US REIT Index at ~4%(1)

Source: Bloomberg(1) Kimbell and the US REIT Index (^RMZ) yield rates are as of 10/29/2019.

28

Appendix

29

History

Kimbell has a strong track record of success as a natural consolidator in the mineral and royalty industry

With a handshake agreement in 1998, a small group of Fort Worth based investors laid the groundwork for what is now Kimbell

Kimbell Royalty Partners, LP formed

Kimbell completed IPO

1998 2015 2016 2017 2018 2019

1998

Oct

ober

201

5 Febr

uary

201

7

Signed agreement to acquire Haymaker assetsM

ay 2

018

July

201

8 Closed acquisition of Haymaker assets for $444 million in cash and equity consideration

Completed conversion to C-Corp for taxation purposes; completed follow-on equity offering

Sept

embe

r 201

8

Dec

embe

r 201

8 Closed drop down acquisition for $90 million in equity consideration

Entered into joint venture to aggregate minerals in the micro-marketJu

ne 2

019

Mar

ch 2

019 Closed Phillips

acquisition from EnCap for $172 million in equity consideration; production nearly quadrupled since IPO

30

Permian12%

Haynesville23%

Appalachia14%

Bakken4%

Eagle Ford11%

Rockies4%

Mid-Continent28%

Permian16%

Appalachia16%

Haynesville5%

Bakken4%

Eagle Ford4%

Rockies<1%

Other26%

Q3’19 Combined Production from the Most Economic Areas (Boe/d)(1)

12,785 Boe/d

Production and Net Royalty Acreage Overview

Net Royalty Acres

(1) Shown on a 6:1 basis. Q3’19 run-rate average daily production excludes prior period production recognized in Q3’19.

144,117

Other20%

31(1) Net Royalty Acres derived from ORRIs are calculated by multiplying Gross Acres and ORRIs.(2) Royalty Interest is inclusive of all other burdens.(3) Acreage as of 9/30/2019.

Defining a Net Royalty Acre

The calculation of a Net Royalty Acre differs across industry participants

Kimbell calculates its Net Royalty Acres(1) as follows: Net Mineral Acres x Royalty Interest(2)

− This methodology provides a clear and easily understandable view of Kimbell’s acreage position

Kimbell Acreage Under Both Methodologies(3)

Net Mineral Acres Royalty Interest Net Royalty Acres

Many companies use a 1/8th convention which assumes eight royalty acres for every mineral acre

− This convention overstates a company’s net royalty interest in its total mineral acreage position as shown below

Net Royalty Acres

Net Royalty Acres (normalized to 1/8th) 1,152,936

144,117

32

In many states, mineral and royalty interests are considered by law to be real property interests and are thus afforded additional protections under bankruptcy law

Mineral Interest owner entitled to ~15-25% of production revenue

Working Interest owner entitled to ~75-85% of production revenue and bears 100% of

development cost and lease operating expense

Senior Secured Debt

Senior Debt

Subordinated Debt

Equity

Mineral Interests Generally Senior to All Claims in Capital Structure

33

Overview of Mineral & Royalty Interests

Minerals

Perpetual real-property interests that grant oil and natural gas ownership under a tract of land

Represent the right to either explore, drill, and produce oil and natural gas or lease that right to third parties for an upfront payment (i.e. lease bonus) and a negotiated percentage of production revenues

NPRIs

Nonparticipating royalty interests

Royalty interests that are carved out of a mineral estate

Perpetual right to receive a fixed cost-free percentage of production revenue

Do not participate in upfront payments (i.e. lease bonus)

ORRIs

Overriding royalty interests

Royalty interests that burden the working interests of a lease

Right to receive a fixed, cost-free percentage of production revenue (term limited to life of leasehold estate)

Illustrative Mineral Revenue Generation

Unleased MineralsRevenue Share KRP: 100% Operator: 0%

Cost Share KRP: 100% Operator: 0%

Lease Termination Upon termination of a lease,

all future development rights revert to KRP to explore or lease again

KRP Issues a Lease KRP receives an upfront

cash bonus payment and customarily a 20-25% royalty on production revenues

In return, KRP delivers the right to explore and develop with the operator bearing 100% of costs for a specified lease term

Leased MineralsRevenue Share KRP: 20-25% Operator: 75-80%

Cost Share KRP: 0% Operator: 100%

1 2 3 4

34

Historical Selected Financial DataNon-GAAP Reconciliation (in thousands)

Net loss $ (28,914) Depreciation and depletion expense 15,098 Interest expense 1,468 Provision for income taxes 103

Consolidated EBITDA $ (12,245) Impairment of oil and natural gas properties 34,880 Unit-based compensation 1,810 Gain on commodity derivative instruments, net of settlements (1,684)

Consolidated Adjusted EBITDA $ 22,761

Annualized Consolidated Adjusted EBITDA $ 91,044 Long-term debt (as of 9/30/19) 91,261 Debt to Consolidated Adjusted EBITDA 1.0x

Three Months EndedSeptember 30, 2019

Documents

KRP Investor Presentationkimbellrp.investorroom.com/download/Winter+2019+Investor+Prese… · 33% of Q3’19 production is from EOR units and conventional fields with shallow declines