#1KIMBELL ROYALTY PARTNERS Fall 2021 Investor Presentation#2Disclaimer This presentation includes forward-looking statements relating to the business, financial performance, results, plans, objectives and expectations of Kimbell Royalty Partners, LP ("KRP" or "Kimbell"). Statements that do not describe historical or current facts, including statements about beliefs and expectations and statements about the federal income tax treatment of future earnings and distributions, future production, Kimbell's business, prospects for growth and acquisitions, and the securities markets generally are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, 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 and does 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"). These include 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, including as a result of the ongoing COVID-19 outbreak and decisions regarding production and pricing by the Organization of Petroleum Exporting Countries and other foreign, oil-exporting countries, that could result in downward revisions to the value of proved reserves or otherwise cause operators to delay or suspend planned drilling and completion operations or reduce production levels, 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 drilling operations 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 meet financial 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 may temporarily 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 or completion of drilling operations; risks relating to delays in receipt of drilling permits; risks relating to unexpected adverse developments in the status of properties; risks relating to borrowing base redeterminations by Kimbell's lenders; risks relating to the absence or delay in receipt of government approvals or third-party consents; risks related 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; and other 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 place undue 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 Consolidated Adjusted EBITDA. KRP believes Consolidated Adjusted EBITDA is useful because it allows management to more effectively evaluate KRP'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 EBITDA as net income (loss), net of non- cash unit-based compensation, change in fair value of open derivative instruments, impairment of oil and natural gas properties, distributions from affiliates, equity income in affiliates, loss on debt modification, income taxes, interest expense and depreciation and depletion expense. KRP excludes the foregoing items from net income (loss) in arriving at Consolidated Adjusted EBITDA 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 in understanding 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. Consolidated Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. Consolidated Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues or any other measure of financial performance or liquidity presented in accordance with GAAP. You should not consider Consolidated Adjusted EBITDA in isolation or as a substitute for an analysis of KRP's results as reported under GAAP. Because Consolidated Adjusted EBITDA may be defined differently by other companies in KRP's industry, KRP's computations of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measures of other companies, thereby diminishing its utility. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We disclose only proved reserves in our filings with the SEC. KRP's proved reserves as of December 31, 2019 and December 31, 2020 were estimated by Ryder Scott, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible reserves, which have been estimated by KRP's internal staff of engineers. These estimates are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. 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 KRP's mineral and royalty interests provides additional data. This presentation also contains KRP's internal estimates of potential drilling locations and production, which may prove to be incorrect in a number of material ways. The actual number of locations that may be drilled, as well as future production results, may differ substantially from estimates. This presentation does not constitute the solicitation of the purchase or sale of any securities. This presentation has been prepared for informational purposes only from information supplied by KRP and from third-party sources. Neither KRP 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 projections, estimates and other information contained herein, which speak only as of the date identified on cover page of this presentation. KRP 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 KRP 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. This presentation also contains KRP's estimates of potential tax treatment of earnings and distributions. This tax treatment is the result of certain non-cash expenses (principally depletion) substantially offsetting KRP's taxable income and tax "earnings and profit." KRP's estimates of the tax treatment of company earnings and distributions are based upon assumptions regarding the capital structure and earnings of KRP's operating company, the capital structure of KRP and the amount of the earnings of our operating company allocated to KRP. 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 KRP operates. These estimates are based on current tax law and tax reporting positions that KRP has 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. KIMBELL ROYALTY PARTNERS#3К KIMBELL ROYALTY PARTNERS 1. Company Overview and History#4Kimbell Overview Kimbell is a pure play mineral company with a diverse portfolio of interests in the highest growth shale basins and stable conventional fields with shallow decline rates Company Overview Provides ownership in diversified, high margin, shallow decline assets with zero capital requirements needed to support resilient free cash flow Interests in over 97,000 gross wells across over 13 million gross acres in the US ■ ~96% of all onshore rigs in the Lower 48 are in counties where Kimbell holds mineral interest positions(1) Approximately 2% of acreage is federal land with active fracking and, as a result, no material impact is expected from any potential suspension of permitting or fracking on federal lands in the US ONSHORE CALIFORNIA Kimbell Mineral and Royalty Assets SAN JUANT BASIN BAKKEN THREE FORKS WILLISTON BASIN DJ BASIN WOLFCAMP/ BONE SPRING/ SPRABERRY MIDCONTINENT SCOOP STACK ILLINOIS UTICA BASIN PERMIAN BASIN FORT WORTH BASIN BARNETT TERRYVILLE/ COTTON VALLEY/L HAYNESVILLE SHALE OTHER OTHER TX-LA-MS SALT BASIN WESTERN GULF BASIN EAGLE FORD RESOURCE PLAY KIMBELL ROYALTY PARTNERS USGS NOGA BASIN OR PROVINCE APPALACHIAN BASIN MARCELLUS Investment Highlights High Quality, Diversified Asset Base 15+ years of drilling inventory remaining (2) Superior PDP decline rate of approximately 12% (3) ■ Net Royalty Acre position of approximately 146,000 acres (1) across multiple producing basins provides diversified scale ■ Attractive Tax Structure (4) Substantially all distributions paid to common unitholders from 2021 through 2025 are not expected to be taxable dividend income Prudent Financial Philosophy Net Debt/ TTM EBITDA of 1.7x as of 6/30/21 Kimbell targets long-term leverage of less than 1.5x Actively hedging for two years representing approximately 33% of current production Significant insider ownership with approximately 19% of the company owned by management, board and affiliates ensures shareholder alignment(5) Positioned as Natural Consolidator ■ Kimbell will continue to opportunistically target high quality positions in the highly fragmented minerals arena Significant consolidation opportunity in the minerals industry with approximately $563 billion (6) in market size and limited public participants of scale €2 (1) Acreage numbers include mineral interests and overriding royalty interests. (5) (2) 4 Based on pace of major gross well completions during 2019, which management believes is a more normalized (6) level of activity compared to 2020, which was impacted by the slowdown resulting from the COVID-19 pandemic. See pages 6-8 and 40 for additional detail. (3) (4) Estimated 5-Year PDP average decline rate on a 6:1 basis. See page 15 of this presentation for information concerning the assumptions and estimates underlying the expected tax treatment of distributions. As of 6/30/21. Does not include Kimbell's Series A preferred units on an as-converted basis. Midpoint of market size estimate range. Based on production data from EIA and spot price as of 7/7/2021. Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 18.75%. Assumes a 10x multiple on cash flows to derive total market size. Excludes natural gas liquids ("NGLS") value and overriding royalty interests. KIMBELL ROYALTY PARTNERS#5Q2 2021 Performance Highlights Kimbell generated -$25.1mm of discretionary cash flow in Q2 2021, yielding total unitholders ~$18.8mm in cash distributions and -$6.3mm in expected debt paydown ■ Q2'21 Snapshot Q2 2021 Consolidated Adjusted EBITDA of $28.1mm, and increase of 8% from Q1 2021, a company record Q2 2021 daily production of 14,011 Boe per day (1), up 2% from Q1 2021 Q2 2021 production consisted of 61% from natural gas, 26% from oil and 13% from NGLS (1) Q2'21 Revenue by Basin(2) Other 9% Rockies 7% Permian 25% Bakken 9% $37.6mm Appalachia 8% Eagle Ford 15% Q2 2021 oil, natural gas and NGL revenues (2) of $37.6mm, an increase of 3% from Q1 2021 As of 6/30/2021, Kimbell had 50 rigs actively drilling on its acreage, an increase of 2% from 3/31/2021, which represented approximately 11% market share of all rigs drilling in the continental US(3) Kimbell reaffirms its financial and operational guidance ranges for 2021 Capitalization Table(4) Common Units Outstanding Class B Units Outstanding Total Units Outstanding Unit Price Market Capitalization Net Debt Series A Cumulative Convertible Preferred Units 42,916,472 17,611,579 60,528,051 $11.83 $716,046,843 $149,973,608 55,000,000 Haynesville 15% Mid-Continent 12% Q2'21 Production by Basin (1) Haynesville 25% Other 9% Rockies 7% Bakken 5% 14,011 Boe/d Eagle Ford 10% Appalachia 15% Enterprise Value Tax Status: Annualized Cash Yield (6) $921,020,451 1099-DIV/No K-1 10.5% Permian 17% (1) Shown on a 6:1 basis. Q2'21 run-rate average daily production excludes prior period production of 382 boe/d recognized in Q2'21. (4) Unit price and yield calculated as of 7/29/2021. All other financial and operational information are as of 6/30/2021. (2) 5 (3) Q2'21 run-rate oil, natural gas and NGL revenues excludes prior period production recognized in Q2'21. Total Q2'21 oil, natural gas and NGL revenues was $38.8 million. Based on Kimbell rig count as of 6/30/2021 and Baker Hughes U.S. land rig count of 459 as of 7/2/2021. (5) A Class B unit is exchangeable together with a common unit of Kimbell's operating company for a KRP common unit. (6) Reflects the annualized Q2'21 distribution. Mid-Continent 12% KIMBELL ROYALTY PARTNERS#6Portfolio Overview by Basin Kimbell's portfolio consists of high-quality oil and gas assets across almost every major basin the U.S. We believe the portfolio represents a balanced mix of liquids vs. gas with high levels of activity from some of the top operators in the industry. Permian Eagle Ford Haynesville Mid-Continent Bakken Appalachia Rockies Other (1) Total Gross | Net Undeveloped Locations (2)(3) 3,017 | 19.20 1,846 | 17.28 1,309 | 17.04 1,489 | 6.38 2,042 | 4.51 247|2.17 210|1.56 N/A 10,160 | 68.14 Gross | Net Drilled but Uncompleted wells 302 | 0.64 71 | 0.33 73 | 0.27 120 | 0.30 162 | 0.27 22 0.09 49 | 0.05 N/A 799 1.95 ("DUCS")(3)(4) Gross | Net Permits (3)(4) 292 | 0.77 73 | 0.59 39 | 0.15 61 | 0.06 156 | 0.68 39 | 0.13 43 | 0.29 N/A 703|2.67 Q2 2021 Production, 17% 10% 25% 12% 5% 15% 7% 9% 100% % of Total Q2 2021 Production Mix Oil Gas 2% 4% 10% 13% 4% 18% 19% 70% Liquids 52% 69% Liquids 6% 50% Liquids 30% 31% NGL 94% 57% 21% 22% 16% 12% 13% 28% 26% 26% 43% 24% 76% Liquids Liquids 17% Liquids 44% Liquids 38% Liquids 39% Liquids 66% 83% 56% 62% 61% Avg. Gross Horizontal wells per Drilling Spacing Unit ("DSU") (5) Rigs (4) 12.0 6.9 5.9 6.8 8.5 7.6 10.5 N/A 8.3 23 3 11 1 0 0 50 OXY bpx energy bpx energy devon Continental RESOURCES PIONEER NATURAL RESOURCES EP ENERGY Vine Ovintiv HESS OIL & GAS Top Operators EST ✗TO ENERGY PDC ENERGY HighPoint CAERA JONAH ENERGY LLC devon Seogresources RESOURCES= Хто Seog resources GEP CIMAREX XTO Cabot Oil & Gas Corporation Seogr MACPHERSON OXY eog resources ENERGY ENERGY HAYNESVILLE, LLC Note: Includes only horizontal locations. Q2'21 run-rate average daily production is shown on a 6:1 basis and excludes prior period production of 382 boe/d recognized in Q2'21. Represents Kimbell's minor basins in this presentation. Includes basins such as Uinta, San Juan, Barnett, as well as other miscellaneous conventional properties. (1) 6 (2) (3) Locations only include Kimbell's major properties in major basins and do not include minor properties, which generally have less than 0.1% net revenue interest and are time consuming to quantify, but in the estimation of Kimbell's management could add up to an additional 20% to Kimbell's net inventory in the aggregate. Assumes forecasted pricing of $55.00 / $2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCS and small interest wells (minor properties). (4) As of 6/30/2021. (5) Gross horizontal wells per DSU from internal reserves database as of 3/31/2021, DSU sizes vary. KIMBELL ROYALTY PARTNERS#7Portfolio Transparency & Defining Upside Potential Kimbell's acreage position contains an estimated 15 years (1) of drilling inventory across its major(2) Portfolio Transparency & Defining Upside Potential properties alone ■ We believe that Kimbell is known for its superior proved developed producing ("PDP") reserves and five-year PDP decline rate of 12%, but upside potential from its extensive drilling inventory is not fully appreciated by the market ■ As of March 31, 2021, we had identified 10,160 gross / 68.14 net (100% NRI) total upside locations (3) on major(2) properties alone, which represents an estimated ~15 years(1) of drilling inventory. Major properties comprise approximately 80% of our portfolio. Management estimates that minor (2) properties can potentially add up to 20% to our net inventory, which implies our total upside inventory could potentially be as high as 85.2 net locations ■ Used conservative spacing assumptions relative to our peers, averaging 12 gross horizontal wells/DSU in the Permian. The Permian, Eagle Ford, and Haynesville basins account for approximately 80% of the total undrilled net inventory in Kimbell's portfolio ■ We estimate that only 4.5 net wells are needed per year to maintain production, which reflects approximately 19 years of drilling inventory at this drilling rate Virtually no upside locations on federal (BLM) acreage, or in Colorado or California ■ As of June 30, 2021, Kimbell had 799 gross / 1.95 net DUCs and 703 gross / 2.67 net permitted locations on its major (2) properties alone ■ Upside analysis was reviewed by Ryder Scott, a leading third-party independent international engineering firm Note: Assumes forecasted pricing of $55.00 / $2.75 flat. All inventory figures as of March 31, 2021, unless specified separately. See page 40 in appendix for further details on process and methodology. Based on pace of major gross well completions during 2019, which management believes is a more normalized level of activity compared to 2020, which was impacted by the slowdown resulting from the COVID-19 pandemic. (1) 7 (2) (3) Locations only include Kimbell's major properties in major basins and do not include minor properties, which generally have less than 0.1% net revenue interest and are time consuming to quantify, but in the estimation of Kimbell's management could add up to an additional 20% to Kimbell's net inventory in the aggregate. For a description of major properties and basins, see page 6. Does not include DUC inventory. KIMBELL ROYALTY PARTNERS#8Upside Location Drilling Inventory (Major (1) Properties Only) Gross Location Breakdown (2) Appalachia Rockies 2% 2% Bakken 20% Permian 30% 10,160 Gross Locations Mid-Con 15% Eagle Ford 18% Net Location Breakdown (2) Appalachia 3% Rockies 2% Bakken 7% Permian 28% Mid-Con 10% 68.14 Net Locations Haynesville 25% Eagle Ford 25% Haynesville 13% Remaining Drilling Inventory by Basin (2) Basin Permian Eagle Ford Haynesville Mid-Con Bakken Appalachia Rockies Total (Major Properties Only) Major Gross Locations 3,017 Major Net Locations 19.20 Avg. Gross Horizontal Wells/DSU(3) 12.0 1,846 17.28 6.9 1,309 17.04 5.9 1,489 6.38 6.8 2,042 4.51 8.5 247 2.17 7.6 210 1.56 10.5 10,160 68.14 8.3 Locations only include Kimbell's major properties in major basins and do not include minor properties, which generally have less than 0.1% net revenue interest and are time consuming to quantify, but in the estimation of Kimbell's management could add up to an additional 20% to Kimbell's net inventory in the aggregate. For a description of major properties and basins, see page 6. Assumes forecasted pricing of $55.00/$2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCS and small interest wells (minor properties). Note: Includes only horizontal locations. (1) 8 (2) (3) Gross horizontal wells per DSU from internal reserves database as of 3/31/2021, DSU sizes vary. KIMBELL ROYALTY PARTNERS#9Organic Growth and 5-Year PDP Decline Forecast Prior to the pandemic-related slowdown in 2020, KRP had demonstrated a strong organic compounded annual growth rate of 8% over a 10-year timeframe through 2019 along with a superior PDP decline rate of 12% due to shallow declines from both conventional and unconventional assets Total BOE, , 6:1 1,000,000 100,000 KRP PDP Reserves (2) MBoe (6:1): 42,418 Oil (MBbls): 12,294 Gas (MMcf): 144,233 NGL (MBbls): 6,085 10,000 Jan-10 Jan-11 Jan-12 Jan-13 (2) €2 9 (1) Estimated 5-Year PDP average decline rate on a 6:1 basis. Jan-14 Jan-15 Jan-16 Jan-17 BOE 12% Kimbell Decline Rate (1) Jan-18 Jan-19 PDP Decline Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 Reflects estimated proved oil and gas reserves filed in Kimbell's year-end 2020 reserve report included in its Form 10-K filed with the SEC. Management believes year-end 2020 PDP reserves may be underrepresented due to new wells which began producing at the end of the year which are not included in our estimate. KIMBELL ROYALTY PARTNERS#10Total BOE, 6:1 Drilling Maintenance to Achieve Flat Production KRP had approximately 670 Major / 1,030 Minor (over 1,700 total) gross horizontal wells drilled on its acreage in 2019. Based on our inventory, this implies an estimated ~15 years of drilling inventory. The ~6 net wells drilled on KRP acreage in 2019 resulted in 8% production growth. Through rigorous analysis, it is estimated that only 4.5 net wells per year are needed to maintain a flat production profile going forward 600,000 500,000 400,000 300,000 200,000 100,000 о Jan-18 4.5 net wells needed to maintain flat production Feb-18 Mar-18 Apr-18 May-18 Jun-18 10 (1) Includes upside locations in major and minor properties. Jul-18 Note: Using 2019 as a reference point, which management believes is a more normalized level of activity compared to 2020, which was impacted by the slowdown resulting from the COVID-19 pandemic. Aug-18 Sep-18 Oct-18 At 4.5 net wells per year, Kimbell has approximately 19 years of drilling inventory(1) Nov-18 ■■BOE, 2019 new wells ■BOE exc. 2019 new wells Dec-18 Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 KIMBELL ROYALTY PARTNERS#11DUC and Permit Inventory As of June 30, 2021, Kimbell had 799 gross (1.95 net) DUCs and 703 gross (2.67 net) permitted locations on its acreage (1) Basin Gross DUCs (2) Gross Permits (2) Net DUCs (2) Net Permits (2) Permian 302 292 0.64 0.77 Eagle Ford 71 73 0.33 0.59 Haynesville 73 39 0.27 0.15 Mid-Continent 120 61 0.30 0.06 Bakken 162 156 0.27 0.68 Appalachia 22 39 0.09 0.13 Rockies 49 43 0.05 0.29 Total 799 703 1.95 2.67 (1) (2) 11 These figures pertain only to Kimbell's major properties and do not include possible additional DUCs and permits from Kimbell's minor properties, which generally have a net revenue interest of 0.1% or below and are time consuming to quantify but, in the estimation of Kimbell's management, could add an additional 20% to Kimbell's net inventory. As of 6/30/2021. KIMBELL ROYALTY PARTNERS#12Kimbell's Rig Count Growth Over Time Active Rigs on Acreage by Basin (1) Bakken 12% Appalachia Eagle Ford 6% Rig Count Change since Q1 2017 2% 24 24 50 Rigs Permian 46% 1 1 3 4 Haynesville 22% 15 Mid-Continent 12% 50 3 1 11 616 23 23 1Q'17 2Q'21 ■Permian Eagle Ford ■Mid-Continent ■Rockies Haynesville Appalachia Kimbell's Rig Count and Market Share Growth Bakken Other 9.1% 9.6% 9.8% 10.4% 10.6% 11.6% 12.0% 11.7% 11.8% 10.9% 6.9% 7.3% 89 89 82 3.0% 2.6% 2.3% 2.1% 2.4% 2.5% 81 77 75 71 24 24 21 23 25 19 29 29 49 39 30 50 50 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 Total KRP Rig Count 2Q'19 3Q'19 4Q'19 1Q'20 2Q'20 3Q'20 4Q'20 1Q'21 2Q'21 KRP Market Share % (2) Defined as total rigs running on Kimbell's acreage as of 6/30/2021 divided by the Baker Hughes U.S. land rig count of 459 as of 7/2/2021. (1) Rig count as of 6/30/2021. (2) 12 KIMBELL ROYALTY PARTNERS#13Active Rigs Drilling on Kimbell's Acreage (as of 6/30/2021) Kimbell has 50 active rigs (94% horizontal) drilling on our acreage at no cost to us Permian Mid-Continent 13 Well Name 1 STEDE BONNET-17 Operator BLACKBEARD 2 PRIDDY-FISCHER 10-10H 3 THUMPER C 14-23-3SH 4 YOSEF THE MOUNTAINEER 29-41 D-5WB 5 QUATTLE-ROGERS 6D-11H PIONEER SABALO BIRCH County/State CRANE, TX GLASSCOCK, TX HOWARD, TX HOWARD, TX Well Name 35 BRADFORD 23_14-15N-10W-2HX 36 COLUMBINE 22_15_10-15N-10W-3HXX 37 PETERS 1407-2H-15X 38 NELDA-5-4X33H PIONEER MARTIN, TX 39 ENGLAND-1H-9 6 QUATTLE-ROGERS 61-6H PIONEER MARTIN, TX 40 SALSMAN-2 Operator County/State BLAINE, OK BLAINE, OK DEVON ENERGY DEVON ENERGY OVINTIV GULFPORT ENERGY CITIZEN ENERGY III STEPHENS & JOHNSON CANADIAN, OK GRADY, OK MCCLAIN, OK OKLAHOMA, OK 7 DIAMOND RIO 9-16M-2813H 8 DIAMOND RIO 9-16N-2815H 9 GERMANIA S42C-3H 10 GERMANIA SPBY S43D-4H 11 LHS RANCH 40-04 0401-0401BH 12 SALLY W260-15H 13 WTH 24-13 B-221 14 BARRACUDA G-C 06H 15 SACROC UNIT-325-4A 16 LONG SHOT UNIT-5401BH 17 KEIZHA-NEAL 2-04WB 18 FORTY NINER RIDGE UNIT-109H 19 JAMES RANCH UNIT DI 1-701H SUMMIT PIONEER MIDLAND, TX PIONEER MIDLAND, TX Bakken PIONEER MIDLAND, TX PIONEER MIDLAND, TX EXXON MOBIL MIDLAND, TX PIONEER MIDLAND, TX ENDEAVOR MIDLAND, TX CENTENNIAL REEVES, TX KINDER MORGAN SCURRY, TX CONOCOPHILLIPS UPTON, TX UPTON, TX 41 HARRISBURG-4-27H 42 ROLFSRUD-152-96-29-32-7HLW 43 BIGFOOT LE 23-11-#9H 44 EN-JOHNSON A-LE--155-94-2932H-1 45 JORGENSON 158-94-12D-1--2H 46 LCU TRUMAN FEDERAL-5-23H1 HESS PETRO-HUNT CONTINENTAL Well Name Operator County/State CONTINENTAL MCKENZIE, ND OVINTIV MCKENZIE, ND KRAKEN MOUNTRAIL, ND MOUNTRAIL, ND MOUNTRAIL, ND WILLIAMS, ND MEWBOURNE EDDY, NM EXXON MOBIL EDDY, NM 20 APOLLO STATE COM-223H TAP ROCK LEA, NM 21 APOLLO STATE COM-211H TAP ROCK LEA, NM 22 APOLLO STATE COM-222H TAP ROCK LEA, NM Well Name 23 APOLLO STATE COM-134H TAP ROCK LEA, NM 47 CETERA A-1H 48 PARKER UNIT-106H Haynesville 49 CERRITO STATE G-51H Eagle Ford Operator EOG RESOURCES EOG RESOURCES County/State DEWITT, TX KARNES, TX ESCONDIDO RESOURCES II WEBB, TX Well Name Operator BP County/State BOSSIER, LA Appalachia AETHON BOSSIER, LA Well Name Operator COMSTOCK CADDO, LA 50 MCC PARTNERS (WEST) UNIT-16H RANGE RESOURCES County/State WASHINGTON, PA COMSTOCK CADDO, LA INDIGO DE SOTO, LA AETHON DE SOTO, LA DE SOTO, LA COMSTOCK DE SOTO, LA GEOSOUTHERN DE SOTO, LA ROCKCLIFF ROCKCLIFF PANOLA, TX PANOLA, TX 24 HA RA SUV; GARLAND 5-8-17 HC-001-ALT 25 HA RA SUII; SKANNAL 22-15 HC-002-ALT 26 HA RA SUG; EDGAR 31-6-7 HC-002-ALT 27 HA RA SUH;RENREW LANDS 6-7 HC-001-ALT 28 DANCE 15&22-13-14 HC-2 29 HA RC SUBB; HEWITT 8-17 HC-001-ALT 30 HA RC SUD; DESOTO 28-21 HC-002-ALT 31 HA RA SU61;TALLEY 32-29-20 HC-002-ALT 32 HA RA SUT; EDWL 18-19-30 HC-001-ALT 33 MCLAURIN HV UNIT D-4H 34 MCLAURIN HV UNIT B-2H VINE KIMBELL ROYALTY PARTNERS#14Kimbell's Track Record Since IPO Kimbell has returned ~32% of $18.00/unit IPO price via cash dividends in just over four years Production Growth (Boe/d)(1)(2) Net Royalty Acres (2)(3) 14.1 14.2 14.1 13.7 14.0 12.8 12.8 12.6 12.0 11.8 10.1 8.5 69.8 69.8 71.3 71.3 63.0 143.2 143.2 143.2 143.8 143.8 145.9 145.9 145.9 145.9 145.9 131.9 115.3 115.3 3.1 3.1 3.3 3.5 3.7 3.6 III 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19 1Q'20 2Q'20 3Q'20 4Q'20 1Q'21 2Q'21 Distribution Growth 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19 1Q'20 2Q'20 3Q'20 4Q'20 1Q'21 2Q'21 Cash G&A per Boe $5.72 $5.41 $0.31 $5.14 $0.27 $4.46 $4.63 $0.17 $4.95 $0.19 $4.76 $0.13 $0.19 $7.47 $7.33 $6.99 $4.08 $0.38 $6.20 $6.40 $6.32 $3.66 $0.42 $5.65 $3.27 $0.39 $2.90 $0.37 $2.50 $0.40 $5.41 $2.05 $0.45 $4.08 $4.46 $4.63 $4.76 $4.95 $5.14 $4.50 $3.95 $3.82 $3.85 $3.66 $3.30 $3.12 $3.24 $3.26 $3.32 $3.09 $1.62 $0.43 $3.27 $2.81 $2.90 $1.20 $0.42 $2.50 $0.84 $0.36 $0.53 $0.31 $0.23 $0.30 $0.53 $0.23 $0.23 $2.05 $1.62 $1.20 $0.84 (4) 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19 1Q'20 2Q'20 3Q'20 4Q'20 1Q'21 2Q'21 ■Prior Cumulative Distributions ■Quarterly Distributions 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19 1Q'20 2Q'20°3Q'20 4Q'20 1Q'21 2Q'21 Source: Company filings and presentations. (1) Shown on a 6:1 basis. 14 (2) Shown in thousands. (3) Acreage numbers include mineral interests and overriding royalty interests. (4) Stub distribution from 2/8/2017 to 3/31/2017. (5) Q2'20 Cash G&A per Boe excludes the transition services agreement expense of $300,000 related to the acquisition of Springbok Energy Partners I, LLC and Springbok Energy Partners II, LLC (collectively, "Springbok") that was incurred only during Q2'20. KIMBELL ROYALTY PARTNERS#15Expected Favorable Tax Treatment of Earnings and Distributions (1) Kimbell believes the expected favorable federal income tax treatment will enhance the after-tax returns to Kimbell common unitholders ■ Kimbell expects that: The company will pay no material amount of federal corporate income taxes from 2021 through 2027 (less than 5% of Kimbell's estimated pre-tax distributable cash flow for such years) 。 Substantially all distributions paid to common unitholders from 2021 to 2025 will not 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 or reduce an investor's capital loss when it sells its common units 15 (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. KIMBELL ROYALTY PARTNERS#16Kimbell has an Optimal Balance of Unconventional and Conventional Assets Kimbell has approximately 23% 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 oil production has been notably flat over the last 20 years (0.0% 20-Year CAGR). 16 Oil Gas 17.0% 67.7% 32.3% 12.2% 81.6% 18.4% 20.1% ■ Unconventional Conventional EOR ▪ Non-EOR NGL 1.4% ■ Unconventional Conventional EOR ▪ Non-EOR Total Production (Boe)(1) 16.1% 19.7% 76.6% 23.4% 7.3% 73.0% 27.0% 7.3% ■ Unconventional Conventional EOR Non-EOR Note: Graphs reflect estimated production from internal reserve report as of 6/30/2021. (1) Shown on a 6:1 basis ■ Unconventional Conventional EOR Non-EOR KIM BELL ROYALTY PARTNERS#17Investment Highlights - Shallow Decline, High Growth Potential Deep Inventory with Strong Upside ■ 23% of production is from EOR units and conventional fields with shallow declines (1) Superior PDP decline rate of approximately 12% (2) ■ ~96% of all onshore rigs in the Lower 48 are in counties where Kimbell holds mineral interest positions(3) Investment Highlights Diversified Asset Base Net Royalty Acre position of approximately 146,000 acres (1,168,000 NRA normalized to 1/8th) (4) across multiple producing basins provides diversified scale Attractive Tax Structure ■ Kimbell does not expect to pay a material amount of federal corporate income taxes from 2021 through 2027 (less than 5% of Kimbell's distributable cash flow for such years) Substantially all distributions paid to common unitholders from 2021 through 2025 are not expected to be taxable dividend income ■ Status as a C-Corp for tax purposes provides a more liquid and attractive security (no K-1) Positioned as Natural Consolidator ■ 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 approximately $563 billion (5) in market size and limited public participants of scale 17 སྱེ¢� (2) (1) Reflects estimated production from internal reserve report as of 6/30/2021. Estimated 5-Year PDP average decline rate on a 6:1 basis. (3) As of 6/30/2021. (4) Acreage numbers include mineral interests and overriding royalty interests. (5) Midpoint of market size estimate range. Based on production data from EIA and spot price as of 7/7/2021. Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 18.75%. Assumes a 10x multiple on cash flows to derive total market size. Excludes NGL value and overriding royalty interests. KIM BELL ROYALTY PARTNERS#18К KIMBELL ROYALTY PARTNERS 2. Detailed Asset Overview#19Permian Basin Acreage Map Permian Chaves Eagle Ford Yoakum Lea Eddy Culberson Jeff Davis A RIGS PERMITS DUCS KRP Acreage Gaines Haynesville Other Basins Terry Lynn Garza Kent WA MT ND MN ID OR SD WI Mi Dawson Borden Scurry NE IA NV UT ILIN OH PA CO MO CA AZ NM AR AL GA Andrews Man Mitchell AA. Loving Winkler Ector Midland A Glasscock Sterling Reeves Brewster 4.Ward Orane Upton Reagan Callahan Our acreage is in the "sweet spot" of the Permian, with production achieving the best of both worlds: ✓ Stable PDP base production from our long-life, low-decline, conventional assets on the CBP, NW shelf, Eastern Shelf and Spraberry vertical units in the Midland Basin ✓ Unconventional production coming from horizontal activity in the Midland and Delaware basins Irion Gross Acreage Net Royalty Acreage Gross Locations (1) Net Locations (1) Midland Delaware 943,228 7,277 Midland 2,218 12.4 215,576 2,535 Delaware 779 6.4 Other Permian 1,403,973 13,263 Other Permian 20 0.4 Pecos Total 2,662,777 23,075 Total 3,017 19.2 Key Operators Permian Rigs on KRP Acreage 2017A Average 14 2018A Average 21 OXY NATURAL RESOURCES. PIONEER TO 2019A Average 27 2020A Average 18 2021A Average 23 Source: Enverus as of 6/30/2021. (1) 19 Assumes forecasted pricing of $55.00 / $2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCs and small interest wells (minor properties). KIMBELL ROYALTY PARTNERS#20Permian Basin EOR / Waterflood Conventional Production Permian Roosevelt Eagle Ford Haynesville Other Basins 20 20 Chaves Eddy Culberson Jeff Davis KRP Acreage ROBERTS UNIT DOLLARHIDE UNIT FULLERTON CLEARFORK Cochran Hockley LEVELLAND UNITS Crosby Dickens WA MT ND MN OWNBY UNIT ID SD OR W Mi NE IA NV UT CO Yoakum Terry Lynn Carza Kent CA AZ NM KS MO AR ILIN OH PA VA Gaine Andrews SEMINOLE SAN ANDRES COGDELL CANYON REEF AL GA Fisher Dawson Borden Scurry Jone Shackelford MEANS SAN ANDRES GOLDSMITH Martin Howard SACROC UNIT Mitchell Nolan Taylo Callahan Loving Winkler Ector Midland Coke Glasscock Sterling Rünnels Coleman Brown Reeves Source: Enverus as of 6/30/2021. GW OBRIEN Crang SAND HILLS TUBB Tom Green Upton Reagan Concho Irion Key Operators Chevron Pecos YATES FIELD OXY UNIT Crockett KINDER MORGAN INC. KIMBELL ROYALTY PARTNERS#21221 21 Jan-95 Jan-96 EOR BOE, 6:1 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Permian Permian Conventional Overview (EOR / Waterflood) Eagle Ford Historically, KRP's Permian EOR/Waterflood properties have demonstrated a very low decline production profile. Through various production maintenance/optimization methods, we believe we will see an even flatter profile going forward, therefore further mitigating overall decline in the future ⚫ Jan-02 Historical BOE Forecast (no wedge) Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Forecast (With Wedge) Jan-23 Jan-24 Jan-25 Jan-26 Jan-27 Jan-28 Jan-29 Jan-30 KIM BELL ROYALTY PARTNERS Haynesville Other Basins#22Permian Unconventional Upside Overview Permian Delaware Core Area(s) - Eagle Ford CO NM KS Eddy Lea Andrews A Active Rigs Other Rigs KRP Permits son KRP DUCS KRP Acreage Midland Core Area(s) Gaines Loving Winkler eves Dawson Borden BR CO KS MO OK NM MO TAR Haynesville Other Basins Defining Basin Potential and Inventory Permian development spacing defined by geology and development trends by surrounding operators Average of 12.0 gross wells/DSU(1) Only zones annotated by a star were quantified Potential for additional upside in other formations not quantified 3,017 gross/19.2 net (100% NRI) upside locations remain in undrilled inventory(2) 302 gross / 0.6 net DUCs have been identified on KRP's major acreage (3) Delaware Spacing (core areas) Midland Spacing (core areas) 1-2 miles 1 mile 640-1,280 acre DSU Unquantified Upside Unquantified Upside Unquantified Upside Unquantified Upside Brushy Canyon Avalon 1st BS 2nd BS 3rd BS 1-2 miles 1 mile 640-1,280 acre DSU Unquantified Upside Unquantified Upside Unquantified Upside Unquantified Upside Clearfork Upper Spraberry Mid Spraberry Jo Mill Andrews Mag Howard Mitchell Nolan A. • Ector Midla Coke Glasscock Sterling A Winkler Active Rigs 0 Other Rigs Tom Green KRP Permits rane KRP DUCS Aon Reagan Irion KRP Acreage Unquantified Upside Unquantified Upside WC XY WC A WC B Lower WC Basin Contribution to KRP Portfolio Unquantified Upside Unquantified Upside 23 rigs running on KRP's Permian acreage as of June 30, 2021 Lower Spraberry WC A WC B WC C WC D Permian production represents 17% of the 2Q 2021 portfolio (Boe 6:1) Industry-wide rig count growing alongside improvements in oil pricing, with an emphasis in the Permian Basin. KRP's Permian exposure, specifically in the Midland Basin, will continue to benefit with activity Permian is currently 46% of KRP's total rig inventory, and 31% of net DUC and Permit inventory(3) Source: Enverus as of 6/30/2021. Gross horizontal wells per DSU from internal reserves database as of 3/31/2021, DSU sizes vary. (1) 22 22 (2) As of 3/31/2021. (3) As of 6/30/2021. KIMBELL ROYALTY PARTNERS#23Eagle Ford Acreage Map Permian Eagle Ford Schleicher Menard Milam Mason Llano Burnet Williamson Sutton Kimble Kerr Gillespie Blanco Edwards Kendall Val Real Comal Verde Bandera Travis Hays Caldwell Haynesville Other Basins Brazos WA MT ND Burleson Grime MN ID OR SD WI ހ WY {MIS IA NE Lee -> NV UT CO IL IN ОН -PA MO Washington, CA Wall Bastrop AZ NM AR AL GA Fayette Austin Guadalupe Bexar Gonzales Lavaca Kinney Uvalde Medina Zavala Maverick A • RIGS PERMITS • DUCS KRP Acreage Wilson De Witt Colorado • -Wharton Jackson Atascosa Kames Matagorda Victoria Goliad Calhoun immit McMullen Bee Salle Live Oak Refugio Significant exposure to the core Eagle Ford oil window Premium pricing differentials due to proximity to vast pipeline infrastructure A Webb Duval Gross Acreage Net Royalty Acreage Gross Locations (1) Net Locations (1) 624,148 6,730 1,846 17.28 Key Operators Eagle Ford Rigs on KRP Acreage 2017A Average 2018A Average 1 3 bpx energy EP ENERGY Seog resource 2019A Average 8 Zapata Jim Hogg 2020A Average 3 Brooks 2021A Average 3 Source: Enverus as of 6/30/2021. (1) 23 23 Assumes forecasted pricing of $55.00 / $2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCS and small interest wells (minor properties). KIMBELL ROYALTY PARTNERS#24Eagle Ford Upside Overview Permian Eagle Ford Core Area(s) Eagle Ford Bexar Wilson Hays Bastrop Caldwell Fayette Guadalupe Atasco A Kames O A Active Rigs • KRP Permits Bee KRP DUCS Dak Other Rigs KRP Acreage Gonzales Lavaca 0 PO De Witt Goliad Victoria Black Oil Volatile Oil Condensate Wet Gas Dry Gas Source: Enverus as of 6/30/2021. Gross horizontal wells per DSU from internal reserves database as of 3/31/2021, DSU sizes vary. As of 3/31/2021. (1) 24 24 (2) (3) As of 6/30/2021. Haynesville Other Basins Defining Basin Potential and Inventory Eagle Ford development spacing defined by geology and development trends by surrounding operators Average of 6.9 gross wells/DSU(1) Only a single bench in the Eagle Ford was quantified to stay with a conservative yet reasonable underwriting approach Potential for additional upside with "wine-racking" well placement in multiple Eagle Ford benches as well as unquantified formations such as the Austin Chalk 1,846 gross / 17.3 net (100% NRI) upside locations remain in undrilled inventory(2) 71 gross / 0.3 net DUCs have been identified on KRP's major acreage (3) 1 mile 1-2 miles 640-1,280 acre DSU Unquantified Upside Unquantified Upside Unquantified Upside Austin Chalk Eagle Ford Buda Pearsall Basin Contribution to KRP Portfolio • 3 rigs running on KRP's Eagle Ford acreage as of June 30, 2021 • Eagle Ford production represents 10% of the 2Q 2021 portfolio (Boe 6:1) KRP boasts a high concentration of undrilled inventory in the prolific "Karnes trough" Eagle Ford is currently 25% of KRP's net undrilled inventory with a production mix that consists of 69% liquids KIMBELL ROYALTY PARTNERS#25Haynesville Acreage Map Permian Eagle Ford Haynesville Cass Marion Wood Upshur Smith Cherokee Gregg Harrison Panola Rusk ング A Shelby Caddo De Soto Bossier Webster BA Red River Other Basins WA MT ND MN Claiborne. ID SD WI OR NE IA NV UT IL IN OPA CO ks.MO VA CA AZ NM AR AL GA Bienville Natchitoches 94% natural gas which makes Haynesville production resilient through down-swings in oil prices High NRI exposure in what is considered the core of the Haynesville basin (De Soto and Red River Parish) Winn La Salle Nacogdoches Gross Acreage Net Royalty Acreage Grant Gross Locations (1) Net Locations (1) 786,724 7,665 1,309 17.04 A RIGS Haynesville Rigs on KRP Acreage San Augustine Key Operators 2017A Average 2 • PERMITS Angelina 2018A Average 3 DUCS bpx energy Vine GEP 2019A Average 13 OIL & GAS HAYNESVILLE, LLC 2020A Average 8 KRP Acreage 2021A Average 11 Source: Enverus as of 6/30/2021. (1) 25 25 Assumes forecasted pricing of $55.00 / $2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCs and small interest wells (minor properties). KIM BELL ROYALTY PARTNERS#26Haynesville Upside Overview Permian Haynesville Core Area(s) Eagle Ford AA Panola Caddo A Bossier Webster Bienville AA Red River De Soto A Active Rigs Natchitoches • KRP Permits Sabine KRP DUCS Other Rigs KRP Acreage Source: Enverus as of 6/30/2021. Gross horizontal wells per DSU from internal reserves database as of 3/31/2021, DSU sizes vary. (1) 26 (2) As of 3/31/2021. (3) As of 6/30/2021. Haynesville Other Basins Defining Basin Potential and Inventory Haynesville development spacing defined by geology and development trends by surrounding operators Average of 5.9 gross wells/DSU(1) In the core areas shown in the map, only Haynesville upside locations were quantified Potential for additional upside in other formations such as middle Bossier and Cotton Valley sands 1,309 gross / 17.0 net (100% NRI) upside locations remain in undrilled inventory(2) 73 gross / 0.3 net DUCs have been identified on KRP's major acreage (3) 1 mile 1-2 miles 640-1,280 acre DSU Unquantified Upside Unquantified Upside Unquantified Upside Unquantified Upside James Lime Cotton Valley Mid Bossier Haynesville Smackover Basin Contribution to KRP Portfolio • 11 rigs running on KRP's Haynesville acreage as of June 30, 2021 • Haynesville production represents 25% of the 2Q 2021 portfolio (Boe 6:1) Average undeveloped NRI of 1.3% (3) Haynesville is currently 22% of KRP's total rig inventory, and 25% of the net undeveloped inventory KIMBELL ROYALTY PARTNERS#27Other Basins Acreage Map Permian A Eagle Ford Haynesville WA ND MT Bakken OR WY CA NV RIGS PERMITS DUCS KRP Acreage AZ NM SD Rockies TA NE TX KS MO Mid-Continent AR Other Basins Expansive footprint across 28 states in the US Balanced mix of unconventional assets and low-decline conventional properties "Other" basins represent 26% of KRP's current rig count and 22% of the net undrilled inventory WH MI PA OH IN MD WV Appalachia NY MA CT Gross Acreage Net Royalty Acreage Mid-Continent 3,955,148 41,402 Bakken Appalachia 1,569,637 6,051 741,354 23,202 Rockies 74,152 1,036 MS AL Other Total 3,232,561 9,572,852 36,694 108,385 Gross Locations (1) Net Locations(1) Mid-Continent 1,489 6.38 Bakken 2,042 4.51 Appalachia 247 2.17 Rockies 210 1.56 Other N/A N/A Total 3,988 14.62 Source: Enverus as of 6/30/2021. (1) 27 27 Assumes forecasted pricing of $55.00 / $2.75 flat. Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 3/31/2021). Excludes DUCs and small interest wells (minor properties). KIMBELL ROYALTY PARTNERS#28К KIMBELL ROYALTY PARTNERS 3. Supplemental Information#29Historical Production Mix (6:1 BOE) by Basin Production in mboepd ■Other ■Rockies Appalachia ■Bakken ■Mid-Continent ■ Haynesville 14.2 14.1 14.1 14.0 13.7 1.3 1.3 1.6 1.3 12.8 12.8 1.2 12.6 0.8 0.8 12.0 11.8 0.6 0.7 1.0 10 2.7 2.6 2.4 1.9 1.9 2.1 2.0 2.1 ■ Eagle Ford 2.8 2.8 10.1 0.4 0.4 0.5 0.7 0.7 ■Permian Basin 0.8 0.7 1.6 0.7 8.5 0.6 1.8 0.5 1.8 1.9 1.7 1.7 0.4 1.5 1.8 1.6 1.1 1.7 1.7 0.5 0.6 0.6 0.6 1.6 0.5 0.5 1.5 1.8 1.7 1.3 0.5 3.3 3.3 3.3 1.5 1.5 3.2 3.5 0.4 1.5 2.3 1.9 1.5 2.9 3.7 1.6 3.6 3.5 1.9 3.3 1.9 1.7 1.6 1.6 3.1 3.1 0.2 0.2 1.0 0.2 1.0 1.0 1.6 1.5 0.8 0.1 0.8 0.8 1.6 1.7 1.6 0.3 0.3 1.6 0.2 1.3 1.4 0.4 0.4 0.5 0.3 1.1 0.3 0.4 0.4 0.5 0.2 0.4 0.9 0.9 3449 0.4 0.4 0.4 0.3 0.5 0.1 2.8 2.8 2.7 0.1 0.4 0.1 0.4 0.1 0.5 0.4 0.2 2.4 2.4 1.9 1.5 1.5 1.6 1.6 1.6 1.7 1.1 0.9 1.0 0.9 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 29 29 KIMBELL ROYALTY PARTNERS#30Consistent Organic Growth over the Last 20 Years Kimbell's assets have proven resilient through multiple commodity price cycles and geopolitical events KRP Organic Net Production Growth (2001-2020)(1) Oil + NGLS (BBL)/Year 2,300,000 2,100,000 1,900,000 1,700,000 1,500,000 1,300,000 1,100,000 900,000 700,000 500,000 300,000 ■ September 11, 2001 100,000 1 U.S. declares war on Iraq Global financial crisis Oil & NGLS OPEC fails to agree on cut Gas 22,000,000 U.S. production reaches 10mm bbl/d 20,500,000 19,000,000 17,500,000 COVID-19 Global 16,000,000 Pandemic T 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Organic Growth - KRP Pro Forma Time Frame Oil+NGLS Gas Total (6:1) Total (20:1) 10-Year 7.8% 3.9% 5.2% 6.4% 7-Year 4.7% 4.1% 4.3% 4.5% 5-Year 3.3% 5.2% 4.4% 3.8% 3-Year 4.8% 4.1% 4.4% 4.6% 1-Year (10.2%) (14.6%) (12.9%) (11.6%) 30 (1) Reflects the compound annual growth rate attributable to Kimbell's currently owned mineral and royalty interests as if it had acquired all such interests on January 1, 2001. 14,500,000 13,000,000 11,500,000 10,000,000 8,500,000 7,000,000 Gas (MCF)/Year KIMBELL ROYALTY PARTNERS#31Minerals are Subsurface Real Estate Kimbell's PDP reserves have grown by approximately 175% since 2017 through a combination of acquisitions and organic PDP reserve growth, akin to adding additional floors to a subsurface building 31 15,403 MBoe PDP Reserves 33,633 MBoe Acquisitions 17,473 MBoe Plus: Revisions 2,970 MBoe PDP Reserves Less: Production 2,213 MBoe 40,912 MBoe Acquisitions 4,661 MBoe Plus: Revisions 7,134 MBoe PDP Reserves Less: Production 4,516 MBoe 42,418 MBoe Acquisitions 4,286 MBoe Plus: Revisions 2,292 MBoe PDP Reserves Less: Production 5,072 MBoe YE 2017 YE 2018 YE 2019 YE 2020 Our sub-surface real estate continues to grow and our ~11% yield is over 3x the yield of the US REIT Index at ~3%(1) Source: Company filings and Bloomberg. (1) Kimbell and the US REIT Index (^RMZ) yield rates are as of 7/29/2021. KIMBELL ROYALTY PARTNERS#32Sustainable PDP Reserves Kimbell has one of the best historical reserve-to-production ratios in the minerals industry (and overall energy sector) at 8.3 years 2020 Year-End PDP Reserves/Q4 2020 Annualized Daily Production (1) Years of PDP Reserves 8.3 7.2 4.6 4.4 3.7 Kimbell Peer 1 Peer 2 Peer 3 Peer 4 Source: Company filings. (1) 32 Calculation of years involves the net PDP reserves (MBoe) as of 12/31/2020, divided by the annualized Q4 2020 average daily production (MBoe). Peer list includes BSM, FLMN, MNRL and VNOM. KIMBELL ROYALTY PARTNERS#3333 October 2015 1998 With a handshake agreement in 1998, a small group of Fort Worth based investors laid the groundwork for what is now Kimbell February 2017 Kimbell completed IPO History Kimbell has a strong track record of success as a natural consolidator in the mineral and royalty industry 1998 2015 2016 2017 2018 Kimbell Royalty Partners, LP formed May 2018 Signed agreement to acquire Haymaker assets HAYMAKER MINERALS & ROYALTIES September 2018 July 2018 Completed conversion to C-Corp for taxation purposes; completed follow-on equity offering Closed acquisition of Haymaker assets for $444 million in cash and equity consideration March 2019 December 2018 Closed drop down acquisition for $90 million in equity consideration Closed Phillips acquisition from EnCap for $172 million in equity consideration; production nearly quadrupled since IPO June 2019 Entered into joint venture to aggregate minerals in the micro- market December 2019 Closed $36 million acquisition of mineral and royalty interests from Buckhorn Resources in all-equity transaction 2019 2020 November 2019 Closed the acquisition of various mineral and royalty interests in Oklahoma for $10 million April 2020 Closed $123 million acquisition of mineral and royalty interests from Springbok for cash and equity consideration KIMBELL ROYALTY PARTNERS December 2020 Closed on credit agreement amendment, increasing total commitments from $225 million to $265 million#34Production and Net Royalty Acreage Overview Q2'21 Production from Some of the Most Economic Areas (Boe/d)(1) Other 9% Other 25% Net Royalty Acres (2) Rockies 7% Haynesville 25% Bakken 5% Rockies <1% 14,011 Boe/d Eagle Ford 10% Eagle Ford 5% 145,855 Appalachia 15% Bakken 4% Permian 17% Mid-Continent 12% Haynesville 5% (1) (2) Shown on a 6:1 basis. Q2'21 run-rate average daily production excludes prior period production of 382 boe/d recognized in Q2'21. Acreage as of 6/30/2021. 34 Mid-Continent 28% Permian 16% Appalachia 16% KIMBELL ROYALTY PARTNERS#35Defining 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 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) Kimbell Acreage Under Both Methodologies (3) 145,855 (1) (2) Net Royalty Acres derived from ORRIS are calculated by multiplying Gross Acres and ORRIs. Royalty Interest is inclusive of all other burdens. 55 35 (3) Acreage as of 6/30/2021. 1,166,840 KIMBELL ROYALTY PARTNERS#3636 36 Mineral Interests Generally Senior to All Claims in Capital Structure 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 Senior Secured Debt Senior Debt Subordinated Debt Equity Working Interest owner entitled to ~75-85% of production revenue and bears 100% of development cost and lease operating expense KIMBELL ROYALTY PARTNERS#3737 34 Overview of Mineral & Royalty Interests 1 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 2 Unleased Minerals KRP Issues a Lease KRP receives an upfront 3 4 Leased Minerals Revenue Share KRP: 100% ▸ Operator: 0% Cost Share ་ KRP: 100% Operator: 0% 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 Revenue Share ་ KRP: 20-25% Operator: 75-80% Cost Share ▸ KRP: 0% Operator: 100% Lease Termination Upon termination of a lease, all future development rights revert to KRP to explore or lease again KIMBELL ROYALTY PARTNERS#38Positioned for Growth Through Acquisitions ✓ Acquisitions from Current Sponsors Existing Kimbell Sponsors' remaining assets have production and reserve characteristics similar to Kimbell's existing portfolio Ownership position in Kimbell incentivizes Kimbell's Sponsors to offer Kimbell the option to acquire additional mineral and royalty assets Consolidation of Private Mineral Companies ✓ ~$563 billion market with minimal amount in publicly traded mineral and royalty companies - Excludes value derived from Overriding Royalty Interests ✓ Highly fragmented private minerals market with significant capital invested by sponsor-backed mineral acquisition companies ✓ Lack of scale is proving difficult for sponsors to monetize investments via IPOs ✓ Kimbell is uniquely positioned to capitalize on private equity need for liquidity and value enhancement Sizing the Minerals Market Total Minerals Market Size(1): ~$563 billion Market Opportunity: 99% Total Public Company Enterprise Value(2): 1% Source: EIA and S&P Capital IQ. (1) Midpoint of market size estimate range. Based on production data from EIA and spot price as of 7/7/2021. Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 18.75%. Assumes a 10x multiple on cash flows to derive total market size. Excludes NGL value and overriding royalty interests. 38 (2) Enterprise values of KRP, BSM, FLMN, MNRL and VNOM as of 7/27/2021. KIMBELL ROYALTY PARTNERS#39Highest Cash Flow Yield Across Multiple Sectors Kimbell offers an attractive -11% yield versus the rest of the public space, including integrated companies 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. Distribution/Dividend Yield Comparison 10.5% 8.0% KIMBELL ROYALTY PARTNERG 3.8% 3.0% 2.2% 2.0% 1.3% RoyaltyCo's Integrateds MSCI REIT Index Large-Cap E&P Precious Metal Producers S&P 500 39 Source: Capital IQ and Bloomberg as of 7/29/2021. RoyaltyCo: Average of VNOM, BSM, FLMN, MNRL and KRP distribution yield; Large-Cap E&Ps: Includes APA, COP, HES, MRO, MUR, OXY, DVN, OVV, COG; Integrateds: Includes CVX, XOM, CNQ, CVE, IMO, SU; Precious metal producers: Includes ABX, AEM, FCX, NEM, OR, RGLD, WPM. KIMBELL ROYALTY PARTNERS#40Process and Methodology Kimbell Process & Methodology Kimbell did not book any upside reserves in its year-end 2020 reserve report included in its Form 10-K filed with the SEC For purposes of this exercise, Kimbell's upside analysis was reviewed by Ryder Scott, a leading third-party independent international engineering firm. Based on the SPE-PRMS (1) reserve definitions, these locations fall under the general classifications of Proved Undeveloped (PUD), Probable and Possible reserves (2) Kimbell's upside development spacing utilizes geology, development trends by offset operators and current rig counts, and is consistent with our historically conservative underwriting approach Kimbell only focused on its major properties and upside locations on minor properties were not identified. With ownership in over 13 million gross acres, we believe that upside drilling locations on our minor properties, which generally have net revenue interests of 0.1% or below, can be significant in the aggregate, and potentially could add up to an additional 20% to Kimbell's net drilling inventory 40 (1) (2) Petroleum Resources Management System prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE); reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), Society of Exploration Geophysicists (SEG), Society of Petrophysicists and Well Log Analysts (SPWLA), and European Association of Geoscientists & Engineers (EAGE), March 2007 and revised June 2018. PUD, Probable, and Possible reserves reflect estimates from internal reserves database as of 3/31/2021. KIMBELL ROYALTY PARTNERS#41Historical Selected Financial Data Non-GAAP Reconciliation (in thousands) Three Months Ended June 30, 2021 Net income Depreciation and depletion expense Interest expense Provision for income taxes $ 3,711 8,337 2,102 Cash distribution from affiliate 273 Consolidated EBITDA $ 14,423 Unit-based compensation 2,744 Loss on derivative instruments, net of settlements 11,043 Cash distribution from affiliate 131 Equity income in affiliate (274) Consolidated Adjusted EBITDA $ 28,067 Q3 2020 - Q1 2021 Consolidated Adjusted EBITDA (1) 60,962 Trailing Twelve Month Consolidated Adjusted EBITDA $ 89,029 Long-term debt (as of 6/30/21) 162,934 Cash and cash equivalents (as of 6/30/21) (12,961) Net debt (as of 6/30/21) $ 149,973 Net Debt to Trailing Twelve Month Consolidated Adjusted EBITDA 1.7x 41 (1) Consolidated Adjusted EBITDA for each of the quarters ended September 30, 2020, December 31, 2020 and March 31, 2021 was previously reported in a news release relating to the applicable quarter, and the reconciliation of net loss to consolidated Adjusted EBITDA for each quarter is included in the applicable news release. KIMBELL ROYALTY PARTNERS