Slides
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Spring 2026 Investor Presentation
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DisclaimerThis presentation includes forward-looking statements relating to the business, financial performance, results, production and other guidance and prospects for growth, 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 doesnot 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 andother 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 potentialdeclines in prices for oil and natural gas, including as a result of decisions regarding production and pricing by the Organization of Petroleum Exporting Countries and other foreign, oil-exporting countries, 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 production levels, which would adversely impact cash flow; risks relating tothe impairment of oil and natural gas properties; risks related to changes in U.S. trade policy and the impact of tariffs; risks relating to the availability of capital to fund drilling operations that can be adversely affected by adversedrilling results; production declines; 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 hedgingactivities; 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 reduceproduction 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 tounexpected 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 Form10-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 Adjusted EBITDA. KRP believes Adjusted EBITDA is useful because itallows 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’smanagement uses Adjusted EBITDA to evaluate cash flow available to pay distributions to its unitholders. Kimbell defines Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, incometaxes, impairment of oil and natural gas properties, non-cash unit-based compensation and unrealized gains and losses on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided byoperating activities as determined by GAAP. KRP excludes the foregoing items from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industrydepending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding andassessing 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 Adjusted EBITDA.Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gasliquids revenues or any other measure of financial performance or liquidity presented in accordance with GAAP. You should not consider Adjusted EBITDA in isolation or as a substitute for an analysis of KRP’s results as reportedunder GAAP. Because Adjusted EBITDA may be defined differently by other companies in KRP’s industry, KRP’s computations of 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 deliverableby 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, 2024 and December 31, 2025 were estimated by RyderScott, 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 naturemore 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 andnatural 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 theavailability 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, includinggeological 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 asfuture 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 theprojections, 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 liabilitybased, 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 andother 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 andestimates 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 taxableincome 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 capitalstructure 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, orchanges 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 whichthe 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 areencouraged to consult with their tax advisor on this matter.
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1. Company Overview and History
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Kimbell Overview 4 Investment HighlightsKimbell is a pure play mineral company offering a unique 10.5% annualized cash distribution yield(1)Kimbell Mineral and Royalty AssetsCompany OverviewHigh Quality, Diversified Asset Base12+ years of drilling inventory remaining(3)Shallow PDP decline rate of approximately 14%(4)Net Royalty Acre position of approximately 158,353 acres(2)across multiple producing basins provides diversified scaleAttractive Tax StructureApproximately 100% of the distribution to be paid on March 25, 2026 is estimated to constitute non-taxable reductions to the tax basis of each distribution recipient’s ownership interest in Kimbell, and should not constitute dividends for U.S. federal income tax purposes(5)Prudent Financial PhilosophyNet Debt / TTM Adjusted EBITDA of 1.5x as of 12/31/2025Actively hedging for two years representing approximately 15% of current productionSignificant insider ownership with approximately 10% of the company owned by management, board and affiliates ensures shareholder alignment(6)Positioned as Natural ConsolidatorKimbell will continue to opportunistically target high quality positions in the highly fragmented minerals arenaSignificant consolidation opportunity in the minerals industry with approximately $657 billion(7)in market size and limited public participants of scale Provides ownership in diversified, high margin, stable assets with zero capital requirements needed to support resilient free cash flowInterests in over 133,000 gross wells across over 17 million gross acres in the US, including highest growth shale basins and stable conventional fields(2)~98% of all onshore rigs in the Lower 48 are in counties where Kimbell holds mineral interest positions(2)Since IPO in 2017, Kimbell has completed over $2.0 billion in M&A transactions, grown run-rate average daily production by over 8x, and returned 75% of $18.00/unit IPO price via quarterly cash distributions (1) Cash distribution yield reflects annualized Q4’25 distribution. Unit price calculated as of 2/09/2026.(2) Well count, M&A, and acreage numbers include mineral interests and overriding royalty interests. (3) Based on estimated major and minor upside net locations of 86.01 divided by estimated 6.8 net wells completed per year to maintain flat production. See pages 9-11 and 37 for additional detail.(4) Estimated 5-Year PDP average decline rate on a 6:1 basis.(5) Kimbell believes these estimates are reasonable based on currently available information, but they are subject to change, including with respect to prior quarters.(6) As of 12/31/25. Does not include Kimbell’s Series A preferred units on an as-converted basis.(7) Midpoint of market size estimate range. Based on production data from EIA and spot price as of 2/10/2026. 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.
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Q4 2025 run-rate average daily production of 25,627 Boe/d(1)Q4 2025 oil, natural gas and NGL revenues of $76.0 millionQ4 2025 net income of approximately $24.8 million and net income attributable to common units of approximately $19.2 millionQ4 2025 consolidated Adjusted EBITDA of $64.8 millionCash distribution of $0.37 per common unit85 active rigs drilling on Kimbell’s acreage, representing approximately 16% market share of U.S. land rig count(2)Conservative Net Debt to TTM Consolidated Adjusted EBITDA of 1.5xCapitalization Table(3)$76.0 mm25,627 Boe/d Q4 2025 Highlights 5(1) Shown on a 6:1 basis.(2) Based on Kimbell rig count as of 12/31/2025 and Baker Hughes U.S. land rig count of 527 as of 12/30/2025.(3) Unit price and yield calculated as of 2/09/2026. All other financial and operational information are as of 12/31/2025.(4) A Class B unit is exchangeable together with a common unit of Kimbell’s operating company for a KRP common unit. Q4’25 SnapshotIn Q4’25, Kimbell generated $76.0 million in Oil, Natural Gas and NGL Revenues, $64.8 million Consolidated Adjusted EBITDA, with run-rate average daily production of 25,627 Boe/d (6:1)Q4’25 Revenue by Basin (5) Please reference page 38 for consolidated adjusted EBITDA non-GAAP reconciliation.(6) Reflects the annualized Q4’25 distribution.Q4’25 Run-Rate Production by Basin(1)Common Units Outstanding 93,396,488Class B Units Outstanding(4)14,491,540Total Units Outstanding 107,888,028Unit Price $14.08Market Capitalization $1,519,063,434Total Debt $441,500,000Cash and Cash Equivalents (43,977,155)Net Debt $397,522,845Series A Cumulative Convertible Preferred Units $162,500,000Enterprise Value $2,079,086,279Q4 2025 Consolidated Adjusted EBITDA $64,824,563TTM Consolidated Adjusted EBITDA(5)$268,057,438Net Leverage Ratio 1.5xTax Status: 1099-DIV/ No K-1A nnualized Cash Distribution Yield(6)10.5%
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$1.20 $2.90 $4.46 $5.14 $6.46 $8.45 $10.13 $11.85 $1.20 $1.70 $1.56 $0.68 $1.32 $1.99 $1.68 $1.72 $1.57 $1.20 $2.90 $4.46 $5.14 $6.46 $8.45 $10.13 $11.85 $13.42 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025Prior Cumulative DistributionsQuarterly Distributions Kimbell’s Track Record Since IPO 6Source: Company filings and presentations.(1) Acreage numbers include mineral interests and overriding royalty interests.(2) Average Full Year 2025 Cash G&A per Boe.(3) Boe shown in thousands, and on a 6:1 basis. 11# of major M&A transactions closed since IPOGross acres acquired since IPO(1)Invested in M&A since IPOReduced Cash G&A / Boe by ~66% since IPO(2) $444mmCash & Equity$230mmCashJuly 2018January 2025TransactionSize / ConsiderationClose DateSelected Acquisitions $271mmCash & EquityDecember 2022Kimbell has returned ~75% of $18.00/unit IPO price via cash distributions since 2017Cash Distribution GrowthRun-Rate Average Daily Production Growth (Boe/d)(3)Kimbell has grown run-rate average daily production by ~8x since IPO ~12.5mm$2.0Bn$2.51/Boe$455mmCashSeptember 2023 Private Seller3.1 3.1 3.3 3.5 3.7 3.6 8.5 10.1 12.0 11.8 12.8 12.8 12.6 14.1 14.2 14.1 13.7 14.0 14.1 14.0 14.4 14.9 15.0 15.4 17.0 17.6 19.8 24.3 24.7 24.1 23.8 24.1 25.5 25.4 25.5 25.6
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2026E Distribution / Common Unit Sensitivity @ 75% Payout RatioOil Price ($/Bbl)$1.43$50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00$2.00$1.02 $1.12 $1.21 $1.31 $1.41 $1.50 $1.60$2.50$1.08 $1.17 $1.27 $1.36 $1.46 $1.55 $1.65$3.00$1.13 $1.23 $1.32 $1.42 $1.51 $1.61 $1.70$3.50$1.18 $1.28 $1.37 $1.47 $1.56 $1.66 $1.75$4.00$1.24 $1.33 $1.43 $1.52 $1.62 $1.71 $1.81$4.50$1.29 $1.38 $1.48 $1.58 $1.67 $1.77 $1.86$5.00$1.34 $1.44 $1.53 $1.63 $1.72 $1.82 $1.912026E Annualized Distribution Yield Sensitivity @ 75% Payout RatioOil Price ($/Bbl)$1.90$50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00$2.007.3% 8.0% 8.6% 9.3% 10.0% 10.7% 11.3%$2.507.7% 8.3% 9.0% 9.7% 10.4% 11.0% 11.7%$3.008.0% 8.7% 9.4% 10.1% 10.7% 11.4% 12.1%$3.508.4% 9.1% 9.8% 10.4% 11.1% 11.8% 12.5%$4.008.8% 9.5% 10.1% 10.8% 11.5% 12.2% 12.8%$4.509.2% 9.8% 10.5% 11.2% 11.9% 12.5% 13.2%$5.009.5% 10.2% 10.9% 11.6% 12.2% 12.9% 13.6%Nat Gas Price ($/Mcf)Nat Gas Price ($/Mcf) Full Year 2026 Guidance 7Source: Management Guidance as of 2/26/2026. Per Unit metrics assume 93,396,488 common units, 14,491,540 Class B units, and $162.5 million face value of 6.00% Series A Cumulative Convertible Preferred Units outstanding. (1) Cash distribution yield reflects expected sum of Q1 2026 through Q4 2026 distributions, assuming 75% payout ratio. Distribution yield calculated based on unit price as of 2/09/2026.(2) Other assumptions include existing hedges, $250k lease bonus revenue / quarter, and realized oil, natural gas, and NGL differentials consistent with Average FY 2025 results. Cash interest expense assumes 25% of expected Cash Available for Distribution will be used to pay down RBL facility. FY 2026 Guidance24.0 - 27.0 Mboe/d (6:1)Net Production30% - 34% Oil Production - % of Net Production46% - 50%Natural Gas Production - % of Net Production18% - 22%NGL Production - % of Net Production$1.40 - $2.20 Marketing and Other Expense ($/boe)$2.45 - $2.65Cash G&A ($/boe)$13.00 - $20.00Depreciation & Depletion Expense ($/boe)6.0% - 8.0%Production and ad valorem taxes (% of Oil, Natural Gas, and NGL Revenues)75%Payout Ratio Assuming Mid-Points of Guidance, Kimbell expects attractive risk-adjusted cash distribution yield in 2026(1)(2)
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Superior Value Proposition 8 Dividend Yield(1)>10%Market Cap>$1.5 BillionDebt / Enterprise Value<25%Expected Tax Expected Tax Deferred DividendNYSE + NASDAQ Publicly Traded Companies(~6,100 companies)397 companies24 companies1 companyApproximately 100% of the distribution to be paid on March 25, 2026 is estimated to constitute non-taxable reductions to the tax basis of each distribution recipient’s ownership interest in Kimbell, and should not constitute dividends for U.S. federal income tax purposes(2) Kimbell compares favorably on key traditional investment metrics to publicly traded companies across various industriesOffers unique combination of tax advantaged dividend yield with a strong balance sheet Source: Bloomberg as of 2/09/2026.(1) Dividend yield is defined as a company’s most recent quarterly distribution annualized divided by such company’s current share price.(2) Kimbell believes these estimates are reasonable based on currently available information, but they are subject to change.
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TotalOther(1)RockiesAppalachiaBakkenMid-ContinentHaynesvilleEagle FordPermian10,341 | 73.11N/A148 | 0.98230 | 2.031,308 | 2.502,056 | 10.73911 | 11.611,242 | 12.764,446 | 32.50Gross | NetUndeveloped Locations(2)(3)900 | 4.66N/A8 | 0.046 | 0.0239 | 0.1796 | 0.4062 | 0.3429 | 0.16660 | 3.53Gross | Net Drilled but Uncompleted wells (“DUCs")(3)(4)628 | 2.43N/A6 | 0.024 | 0.04116 | 0.1357 | 0.3427 | 0.1825 | 0.09393 | 1.63Gross | NetPermits(3)(4)100%4%4%6%4%22%13%6%41%Q4 2025 Production,% of Total52%Liquids42%Liquids52%Liquids14%Liquids77%Liquids46%Liquids6% Liquids68%Liquids73%LiquidsQ4 2025Production Mix8.3N/A10.57.68.56.85.96.912.0Avg. Gross Horizontal wells per Drilling Spacing Unit (“DSU”)(5) 85-2-51411746Rigs(4)Top OperatorsNote: Includes only horizontal locations. Q4’25 average daily production is shown on a 6:1 basis. Numbers may not add due to rounding.(1) Represents Kimbell’s minor basins in this presentation. Includes basins such as Uinta, San Juan, Barnett, as well as other miscellaneous conventional properties.(2) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties). Portfolio Overview by Basin 9 Oil Gas NGL Kimbell’s portfolio consists of high-quality oil and gas assets across almost every major basin in 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. (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 15% to Kimbell’s net inventory in the aggregate.(4) As of 12/31/2025.(5) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary. 31%48%21%29%58%14%34%48%17%3%86%11%58%23%19%16%54%29%4%94%2%44%32%24%48%27%25%
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Portfolio Transparency & Defining Upside Potential 10Note: All inventory figures as of December 31, 2025. See page 37 in appendix for further details on process and methodology.(1) Reflects 86.01 net (100% NRI) total upside locations on major and minor properties divided by estimated 6.8 net wells completed to maintain flat production. (2) 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 15% to Kimbell’s net inventory in the aggregate. For a description of major properties and basins, see page 9.(3) Does not include DUC inventory. Portfolio Transparency & Defining Upside PotentialWe believe that Kimbell is known for its superior proved developed producing (“PDP”) reserves and five-year average PDP decline rate of 14%, but upside potential from its extensive drilling inventory is not fully appreciated by the marketAs of December 31, 2025, we had identified 10,341 gross / 73.11 net (100% NRI)total upside locations(3)on major(2)properties alone. Major properties comprise approximately 85% of our portfolio. Management estimates that minor(2)properties can potentially add up to 15% to our net inventory, which implies our total upside inventory could potentially be as high as 86.01 net locationsKimbell applied conservative spacing assumptions relative to our peers, averaging 12 gross horizontal wells/DSU in the Permian. The Permian, Eagle Ford, Haynesville and Mid-Con account for approximately 92% of the total undrilled net inventory in Kimbell’s portfolio Kimbell estimates that only 6.8 net wells are needed per year to maintain production, which reflects over 12 years of drilling inventory including the major and minor locationsVirtually no upside locations on federal (BLM) acreage, or in Colorado or CaliforniaAs of December 31, 2025, Kimbell had 900 gross / 4.66 net DUCs and 628 gross / 2.43 net permitted locations on its major(2)properties alone Kimbell’s acreage position contains over 12 years(1)of drilling inventory across its major and minor(2)properties
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73.11 NetLocationsGross Location Breakdown(2)Upside Location Drilling Inventory (Major(1) Properties Only)Net Location Breakdown(2) 11 Remaining Drilling Inventory by Basin(2)10,341GrossLocationsAvg. Gross Horizontal Wells/DSU(3)Major Net LocationsMajor Gross LocationsBasin12.032.504,446Permian6.912.761,242Eagle Ford5.911.61911Haynesville6.810.732,056Mid-Con8.52.501,308Bakken7.62.03230Appalachia10.50.98148Rockies8.373.1110,341Total (Major Properties Only)Note: Numbers may not add due to rounding. (1) 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 15% to Kimbell’s net inventory in the aggregate. For a description of major properties and basins, see page 9.(2) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties).(3) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary.
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DUC and Permit Inventory 12Note: Numbers may not add due to rounding.(1) 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 15% to Kimbell’s net inventory. Please refer to page 10 for additional detail.(2) As of 12/31/2025. Total Net Wells(2)Net Permits(2)Net DUCs(2)Gross Permits(2)Gross DUCs(2)Basin5.161.633.53393660Permian0.250.090.162529Eagle Ford0.520.180.342762Haynesville0.740.340.405796Mid-Continent0.300.130.1711639Bakken0.060.040.0246Appalachia0.060.020.0468Rockies7.092.434.66628900Total As of December 31, 2025, Kimbell had 900 gross (4.66 net) DUCs and 628 gross (2.43 net) permitted locations on its acreage, which is in excess of estimated 6.8 net wells to maintain flat production(1)
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85 Rigs 51 46 4 7 7 5 8 11 12 14 86 85 3 Q ' 2 5 4 Q' 2 5PermianEagle FordBakkenRockiesHaynesvilleMid-ContinentAppalachiaOther Kimbell’s Rig Count Growth Over Time 13(1) Rig count as of 12/31/2025.(2) Based on Kimbell rig count as of 12/31/2025 and Baker Hughes U.S. land rig count of 527 as of 12/30/2025. Active Rigs on Acreage by Basin(1)Quarter-Over-Quarter Rig Count ChangeKimbell’s Rig Count and Market Share Growth(2)24 2421192325717789 89828175293039495060617374799294909998 98919087908886853%3%2%2%2%2%7%7%9%10%10% 10%11%12%12%12%12%11%12%11%11%10%11%12%13%14%17% 16% 16% 16% 16%15%16% 17% 16% 16%Total KRP Rig CountKRP Market Share %
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Active Rigs Drilling on Kimbell’s Acreage (as of 12/31/25) 14 Kimbell has 85 active rigs (99% horizontal) drilling on our acreage at no cost to us; 66% of rigs are operated by public companies and 34% by private operatorsPermianMid-ConBakkenHaynesvilleEagle FordRockiesWell Name Operator County/State1 CASSELMAN 32-6H APACHE ANDREWS, TX2 CROSSROADS XL-3DN APACHE BORDEN, TX3 BANNER A-1H PETROPLEX ENERGY BORDEN, TX4 ALICE FEE 34-6HCAPITAN ENERGYCULBERSON, TX5 THUNDERBOLT WEST G 28-45-4307H DE CENTRAL GLASSCOCK, TX6 CUDA 46-3 C-3WA DIAMONDBACK GLASSCOCK, TX7 ARROW PEAK 7-6 UNIT-4AH SURGE HOWARD, TX8 ROBINSON D 07-06-3AH SURGE HOWARD, TX9 SALT CREEK FIELD UNIT-C439 OXY KENT, TX10 BACKDOOR SLIDER B-121H CIVITAS LOVING, TX11 BACKDOOR SLIDER H-123H CIVITAS LOVING, TX12 SWAPPORTUNITY STATE C-1153H CONOCOPHILLIPS LOVING, TX13 LAGER 29-0-16-21 D-53H OXY LOVING, TX14 LAGER 29-0-16-21 F-54H OXY LOVING, TX15 MABEE DDA E11-310JH CONOCOPHILLIPS MARTIN, TX16 MABEE DDA E15-403MH CONOCOPHILLIPS MARTIN, TX17 CROSS-HAZELWOOD 35H-108H EXXON MARTIN, TX18 CROSS-HULL 35E-105H EXXON MARTIN, TX19 HAZELWOOD-CROSS 11D-4H EXXON MARTIN, TX20 HULL-CROSS 2L-12H EXXON MARTIN, TX21 NAIL-BURLEY 6A-601H EXXON MARTIN, TX22 NAIL-BURLEY 6J-610H EXXON MARTIN, TX23 NAIL-BURLEY 6N-714H EXXON MARTIN, TX24 NAIL-TILLMAN E1C-503H EXXON MARTIN, TX25 NAIL-TILLMAN E1H-508H EXXON MARTIN, TX26 MOHAWK 71D-1HJ OVV MARTIN, TX27 MOHAWK 71X-11HD OVV MARTIN, TX28 BUCHANAN-FASKEN 41A-101H EXXON MIDLAND, TX29 TREES STATE 5657A-01H CONTINENTAL PECOS, TX30 IDK 57-T1-32X29 F-W106H BP REEVES, TX31 IDK 57-T1-32X29 K-W111H BP REEVES, TX32 REV GF MARIA BREBER STATE UNIT-1215SB CHEVRON REEVES, TX33 TETON 56-2-35-23 K-25H OXY REEVES, TX34 NOELIA A4-9001BH CONOCOPHILLIPS UPTON, TX35 MORGAN-CARLETON 24B-102H EXXON UPTON, TX36 MORGAN-OWENS 24F-6H EXXON UPTON, TX37 SKAGGS-ROBBIE 44E-105H EXXON UPTON, TX38 COUSIN-BESSIE 8C-3H EXXON UPTON, TX39 WOODFIN 16 A-401HU FIREBIRD ENERGY II UPTON, TX40 HERBERT 101C-301HD OVV UPTON, TX41 CALLIE 3-05JM SUMMIT PETROLEUM UPTON, TX42 DIRE WOLF E-8A CRESCENT ENERGY WARD, TX43 CHAOS WC FEDERAL COM-700H MARATHON EDDY, NM44 CANAL 20/19 FED COM-855H MEWBOURNE EDDY, NM45 TAILS CC 10_3 FED COM-43H OXY EDDY, NM46 FORTY NINER RIDGE UNIT-52H STRATA EDDY, NM Well Name Operator County/State47 CABERNET COM-3H-132425X COTERRA BLAINE, OK48 COUGAR 1612-362524-1HM VALIDUS ENERGY II BLAINE, OK49 DEER CREEK 1209-25-36-1-2MXH CAMINO CANADIAN, OK50 TENKILLER LAKE 1108-31-6-2MXH CAMINO CANADIAN, OK51 JUNIOR 10_3-13N-9W-3HX DEVON CANADIAN, OK52 PAYNE 1414-5H-12X-MS TAMWORTH CUSTER, OK53 BASS 0403-313019-2HM VALIDUS ENERGY II GARVIN, OK54 CUADRILLA FED 0405-03-10-2WXH VALIDUS ENERGY II GRADY, OK55 AUDRA 0306 12-13-24-2WHX WARWICK-JUPITER GRADY, OK56 TROUT-2-27-34CHX CRAWLEY PETROLEUM ROGER MILLS, OK57 VELMA 16-4 PA-1H MEWBOURNE ROGER MILLS, OK58 QUARTER CIRCLE S 22-34 IP-1H MEWBOURNE ROGER MILLS, OK59 JACK SPARROW 22-15-2H UPLAND ROGER MILLS, OK60 KELLN 201/152 A-C002DM MEWBOURNE LIPSCOMB, TXWell Name Operator County/State61 LCV RA SU118;MNCL 31&6-16-13HC-004-ALT APEX NATURAL GAS CADDO, LA62 MCFERRN 36&12-16-14HC-1 APEX NATURAL GAS DE SOTO, LA63 HA RA SUL;DIXON 6-1 HU-1-ALT COMSTOCK DE SOTO, LA64 HA RA SUO;SPEIGHTS 5-32-29 HC-002-ALT COMSTOCK DE SOTO, LA65 HA RA SUO;WHITSON 5-32-29 HC-002-ALT COMSTOCK DE SOTO, LA66 HA RA SUEE;HAY 6-7-18 HC-002-ALT EXCO DE SOTO, LA67 HA RA SUEE;LITTLE 6-7-18 HC-001-ALT EXCO DE SOTO, LA68 HA RA SUO; WELLS 22&15-13-16HC-001-ALT EXPAND DE SOTO, LA69 HA RA SUD;SWN PROD 14-23 HC-1 ENSIGHT IV RED RIVER, LA70 HAMBY HEIRS B (AW)-2H SABINE OIL & GAS GREGG, TX71 F14F WERNER-THOMPSON DS-4UH TGNR PANOLA PANOLA, TXWell Name Operator County/State79 RATCLIFFE USA-11-13H MARATHON DUNN, ND80 HAWKEYE-177-1324H EOG MCKENZIE, ND81 TORGERSON-158-94-10B-15-1HS PETRO-HUNT MOUNTRAIL, ND82 RELLA W-5303 13-18 3B CHORD ENERGY WILLIAMS, ND83 GBU APOLLO-14X-12D-S EXXON WILLIAMS, NDWell Name Operator County/State84 SANDLOT-48-23141102-22E SM DUCHESNE, UT85 SANDLOT-66-23141102-22I SM DUCHESNE, UTWell Name Operator County/State72 NELSON A-CASKEY B SA 2-2H BP DEWITT, TX73 NATHO A-NATHO B SA 3-3H BP DEWITT, TX74 ROOSEVELT H-8H EOG GONZALES, TX75 WASHBURN RANCH 01-18H CRESCENT ENERGY LA SALLE, TX76 COPPER C-3H EOG LA SALLE, TX77 BAJOR D-4H BAYTEX LAVACA, TX78 MATRIX CASPIAN BB-64H ESCONDIDO WEBB, TX
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4.50 4.50 4.50 4.50 4.50 4.90 5.80 5.80 5.80 5.80 5.80 5.80 6.50 6.50 6.50 6.80 5.03 5.36 5.44 6.94 6.74 6.86 9.34 8.38 8.20 7.96 7.84 7.21 8.10 7.99 7.07 7.09 40 60 80 100 120 –2.004.006.008.0010.00 Rig Count Net Well InventoryMaintenance WellsWells in Excess of Maintenance LevelRig Count Current Inventory and Rig Count Support Organic Growth 15(1) As of 12/31/2025. Net DUCs + Net Permits = Net Wells. Net DUC and Net Permit inventory, of 7.09 net wells (which is in excess of 6.8 net wells needed to maintain flat production), coupled with 85 rigs actively drilling on Kimbell’s acreage, implies organic production growth potential(1)Kimbell’s near term inventory remains in excess of maintenance activity levels
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Investment Highlights - Stable and Resilient Cashflow 16 InvestmentHighlightsDeep Inventory with Strong UpsideShallow PDP decline rate of approximately 14%(1)Compelling rig activity and Net DUC / Net Permit inventory support organic growthSustainable business model with over 12 years of drilling locations remaining(2)Diversified Asset BaseNet Royalty Acre position of approximately 158,353 acres (1,266,824 NRA normalized to 1/8th)(3)across multiple producing basins provides diversified scaleAttractive Tax StructureApproximately 100% of the distribution to be paid on March 25, 2026 is estimated to constitute non-taxable reductions to the tax basis of each distribution recipient’s ownership interest in Kimbell, and should not constitute dividends for U.S. federal income tax purposes(4)Status as a C-Corp for tax purposes provides a more liquid and attractive security (no K-1)Positioned as Natural ConsolidatorKimbell will continue to opportunistically target high quality positions in the highly fragmented minerals arenaKimbell can capitalize on weak IPO markets by providing an avenue for sponsors looking to exit minerals investmentsSignificant consolidation opportunity in the minerals industry, with approximately $657 billion(5)in market size and limited public participants of scale(1) Estimated 5-Year PDP average decline rate on a 6:1 basis. (2) Based on estimated major and minor upside net locations of 86.01 divided by estimated 6.8 net wells completed per year to maintain flat production. See pages 9-11 and 37 for additional detail.(3) Acreage numbers include mineral interests and overriding royalty interests.(4) Kimbell believes these estimates are reasonable based on currently available information, but they are subject to change.(5) Midpoint of market size estimate range. Based on production data from EIA and spot price as of 2/10/2026. 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.
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2. Detailed Asset Overview
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Permian Basin Acreage Map 18 Other BasinsEagle FordKRP acreage is in the “sweet spot” of the Permian, with production achieving both: Stable PDP base production from long-life, low-decline, conventional assets on the CBP, NW Shelf, Eastern Shelf and Spraberry vertical units in the Midland BasinUnconventional production from active horizontal development in the Midland and Delaware basinsSource: Enverus as of 12/31/2025. Numbers may not add due to rounding.(1) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties).Net Locations(1)Gross Locations(1)16.602,534Midland15.901,912Delaware32.504,446TotalNet Royalty AcreageGross Acreage9,4831,260,214Midland4,831614,297Delaware13,4881,531,517Other Permian27,8023,406,028TotalKey OperatorsPermian Rigs on KRP Acreage242021A Average392022A Average502023A Average492024A Average502025A Average Mid-ContinentHaynesvillePermian
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Permian Basin EOR / Waterflood Conventional Production 19Source: Enverus as of 12/31/2025. COGDELL CANYON REEFSACROCUNITDOLLARHIDE UNITKey OperatorsFULLERTON CLEARFORKMEANS SAN ANDRESGOLDSMITHROBERTS UNITSEMINOLESAN ANDRES OWNBY UNITLEVELLANDUNITS YATES FIELD UNITGW OBRIENSAND HILLS TUBB Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Unquantified Upside Permian Unconventional Upside OverviewPermian 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 quantified4,446 gross / 32.50 net (100% NRI) upside locations remain in undrilled inventory(2)–660 gross / 3.53 net DUCs have been identified on KRP’s major acreage(2) 20 Delaware Core Area(s) Defining Basin Potential and Inventory Basin Contribution to KRP Portfolio46 rigs running on KRP’s Permian acreage as of December 31, 2025Permian production represents 41% of the Q4 2025 portfolio (Boe 6:1)KRP’s highly economic inventory in the core of the prolific Midland and Delaware Basins yields years of future development Permian is currently 54% of KRP’s total rig inventory, and 73% of net DUC and Permit inventory(2)Midland Core Area(s)Source: Enverus as of 12/31/2025.(1) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary. (2) As of 12/31/2025. Delaware Spacing (core areas)Midland Spacing (core areas)1 mile640 – 1,280 acre DSU1 mileUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified Upside Unquantified Upside Unquantified Upside 640 – 1,280 acre DSUUnquantified Upside Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Haynesville Acreage Map 21 Net Royalty AcreageGross Acreage7,9191,428,907Key OperatorsHaynesville Rigs on KRP Acreage132021A Average142022A Average172023A Average92024A Average92025A Average 94% natural gas which makes Haynesville production resilient through down-swings in oil pricesHigh NRI exposure in core of the Haynesville basin (De Soto and Red River Parishes)Net Locations(1)Gross Locations(1)11.61911Source: Enverus as of 12/31/2025.(1) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties). Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Haynesville Upside OverviewHaynesville 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 sands911 gross / 11.61 net (100% NRI) upside locations remain in undrilled inventory(2)–62 gross / 0.34 net DUCs have been identified on KRP’s major acreage(2) 22 Haynesville Core Area(s) Defining Basin Potential and Inventory Basin Contribution to KRP Portfolio11 rigs running on KRP’s Haynesville acreage as of December 31, 2025Haynesville production represents 13% of the Q4 2025 portfolio (Boe 6:1)Average undeveloped NRI of 1.2%(2)Haynesville is currently 13% of KRP’s total rig inventory, and 7% of the major net DUC and Permit inventory(2) 640 – 1,280 acre DSU1 mileUnquantified UpsideUnquantified UpsideUnquantified UpsideUnquantified Upside Source: Enverus as of 12/31/2025.(1) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary.(2) As of 12/31/2025. Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Mid-Continent Acreage Map 23 KRP’s Mid-Continent position is a leader in terms of scale, productivity, rig capture, and depth of inventory Expansive acreage footprint in the SCOOP and STACK spans all product windows, yielding years of development of both oil-weighted and highly productive gas inventorySource: Enverus as of 12/31/2025.(1) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties).Key OperatorsMid-Con Rigs on KRP Acreage82021A Average122022A Average162023A Average202024A Average152025A AverageNet Royalty AcreageGross Acreage48,8325,866,366Net Locations(1)Gross Locations(1)10.732,056 Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Mid-Continent Upside OverviewMid-Continent development spacing defined by geology and development trends by surrounding operators–Average of 6.8 gross wells/DSU(1) in core areas–Only zones annotated by a star were quantified–Potential for additional upside in unquantified formations such as Sycamore and Springer2,056 gross / 10.73 net (100% NRI) upside locations remain in undrilled inventory(2)–96 gross / 0.40 net DUCs have been identified on KRP’s major acreage(2) 24 Mid-Continent Core Area(s) Defining Basin Potential and Inventory Basin Contribution to KRP Portfolio14 rigs running on KRP’s Mid-Continent acreage as of December 31, 2025Mid-Continent production represents 22% of the Q4 2025 portfolio (Boe 6:1)Unconcentrated position with exposure to a diversified set of well-capitalized operators committed to the long-term development of SCOOP/STACKMid-Continent is currently 15% of KRP’s net undrilled inventory(2)Source: Enverus as of 12/31/2025.(1) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary.(2) As of 12/31/2025. STACK Spacing (core areas)1 mile 640 – 1,280 acre DSUUnquantified UpsideOther BasinsEagle Ford PermianMid-ContinentHaynesvilleSCOOP Spacing (core areas)1 mile 640 – 1,280 acre DSUUnquantified UpsideUnquantified UpsideUnquantified Upside
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Eagle Ford Acreage Map 25 Significant exposure to the core Eagle Ford oil windowPremium pricing differentials due to proximity to vast pipeline infrastructure Source: Enverus as of 12/31/2025.(1) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties).Key OperatorsEagle Ford Rigs on KRP Acreage42021A Average62022A Average52023A Average72024A Average52025A AverageNet Royalty AcreageGross Acreage6,730624,148Net Locations(1)Gross Locations(1)12.761,242 Other BasinsEagle FordMid-ContinentHaynesvillePermian
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7 rigs running on KRP’s Eagle Ford acreage as of December 31, 2025Eagle Ford production represents 6% of the Q4 2025 portfolio (Boe 6:1)KRP boasts a high concentration of undrilled inventory in the prolific “Karnes trough”Eagle Ford is currently 17% of KRP’s net undrilled inventory with a production mix that consists of approximately 68% liquids(2) Eagle Ford Upside OverviewEagle 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 Chalk1,242 gross / 12.76 net (100% NRI) upside locations remain in undrilled inventory(2)–29 gross / 0.16 net DUCs have been identified on KRP’s major acreage(2) 26 Eagle Ford Core Area(s) Defining Basin Potential and Inventory Basin Contribution to KRP Portfolio1 mile 640 – 1,280 acre DSUUnquantified UpsideUnquantified UpsideUnquantified Upside Source: Enverus as of 12/31/2025.(1) Gross horizontal wells per DSU from internal reserves database as of 12/31/2025, DSU sizes vary.(2) As of 12/31/2025. Other BasinsEagle FordMid-ContinentHaynesvillePermian
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Other Basins Acreage Map 27 Net Locations(2)Gross Locations(2)2.501,308Bakken2.03230Appalachia0.98148RockiesN/AN/AOther5.511,686Total Expansive footprint across 28 states in the USBalanced mix of unconventional assets and low-decline conventional properties “Other” basins, including Bakken, Appalachia and Rockies, represent 8% of KRP’s current rig count(1)and 7% of the net undrilled inventory(2)Net Royalty AcreageGross Acreage6,1381,640,077Bakken23,203741,354Appalachia1,03674,152Rockies36,6933,232,560Other67,0705,688,143TotalSource: Enverus as of 12/31/2025.(1) As of 12/31/2025.(2) Locations include Permits, proven undeveloped (PUD), Probable, and Possible (per SPE-PRMS reserve definitions based on internal reserves database as of 12/31/2025). Excludes DUCs and small interest wells (minor properties). BakkenAppalachiaRockiesOther BasinsEagle FordMid-ContinentHaynesvillePermian
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3. Supplemental Information
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Historical Run-Rate Average Daily Production Mix by Basin 29 Production in mboepd Note: Shown on a 6:1 basis.0.9 0.9 0.9 1.0 0.9 1.1 1.5 1.5 1.6 1.6 1.6 1.7 1.9 2.4 2.8 2.8 2.7 2.4 2.3 2.4 2.4 2.4 2.4 2.8 4.4 5.6 7.5 9.2 9.7 9.2 8.7 9.5 10.8 11.0 10.4 10.5 0.5 0.4 0.4 0.4 0.5 0.4 0.5 1.1 1.6 1.3 1.4 1.6 1.7 1.6 1.7 1.6 1.6 1.5 1.6 1.5 1.5 1.5 1.8 1.8 1.8 1.8 1.9 1.9 1.7 1.6 1.7 1.5 1.8 1.8 1.6 1.6 0.4 0.4 0.4 0.4 0.4 0.3 1.6 1.9 1.6 1.9 2.9 2.3 1.9 3.2 3.3 3.3 3.3 3.5 3.6 3.5 3.5 4.2 4.2 4.2 4.4 3.7 3.9 4.2 4.4 4.4 4.5 4.0 3.9 3.7 3.2 3.3 0.3 0.4 0.4 0.5 0.3 1.5 1.5 1.5 1.5 1.5 1.8 1.7 1.8 1.7 1.7 1.5 1.6 1.6 1.7 1.8 1.8 1.8 1.7 1.7 1.8 1.9 4.2 4.1 4.3 4.5 4.6 4.6 4.4 5.6 5.5 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.8 0.7 0.7 0.7 0.7 0.7 0.7 1.0 0.9 0.8 1.0 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.8 0.8 1.0 1.0 1.3 1.6 1.7 1.7 1.8 1.8 1.9 2.1 1.9 1.9 2.0 2.1 2.0 2.0 2.0 1.9 1.8 1.8 1.7 1.8 1.7 1.9 1.9 1.7 1.6 1.6 1.6 1.6 1.6 1.6 0.2 0.3 0.3 0.6 0.4 0.6 0.5 0.5 0.4 0.4 0.6 0.8 0.8 0.7 1.0 1.0 0.9 0.9 0.9 0.8 0.8 0.8 0.7 0.8 0.8 0.9 0.8 0.8 0.8 0.8 0.8 1.0 0.9 0.8 0.8 0.8 1.0 1.0 1.0 1.1 1.6 2.8 2.8 2.7 2.6 2.4 1.6 1.3 1.3 1.2 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.2 1.2 1.2 1.2 1.1 1.1 1.2 1.1 1.1 1.1 3.1 3.1 3.3 3.5 3.7 3.6 8.5 10.1 12.0 11.8 12.8 12.8 12.6 14.1 14.2 14.1 13.7 14.014.114.014.4 14.9 15.0 15.4 17.0 17.6 19.8 24.3 24.7 24.1 23.8 24.1 25.5 25.4 25.5 25.6 OtherRockiesAppalachiaBakkenMid-ContinentHaynesvilleEagle FordPermian Basin
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Reserve Replacement 30Kimbell’s growing portfolio of sub-surface real estate generates a 10.5% distribution yield, which is approximately 2.8x the yield of the US REIT Index at ~3.9%(1) Kimbell has grown proved developed reserves by ~5x since IPO through a combination of acquisitions and organic growth, and Kimbell replaced 157% of proved developed reserves in 2025 Source: Company filings and Bloomberg. (1) Kimbell and the US REIT Index (^RMZ) yield rates are as of 2/09/2026.Proved Developed ReservesProved Developed ReservesLess: Production2,213 MboeProved Developed ReservesLess: Production4,516 MboeProved Developed ReservesLess: Production5,072 MboeProved Developed ReservesLess: Production5,240 MboeProved Developed ReservesLess: Production5,558 MboeProved Developed ReservesLess: Production7,373 MboeProved Developed ReservesLess: Production9,102 MboeProved Developed ReservesLess: Production9,403 MboePlus: Revisions2,970 MBoePlus: Revisions7,134 MBoePlus: Revisions2,292 MBoePlus: Revisions5,044 MBoePlus: Revisions3,554 MBoePlus: Revisions8,432 MBoePlus: Revisions11,234 MBoePlus: Revisions10,211 MBoeAcquisitions17,473 MBoeAcquisitions4,661 MBoeAcquisitions4,286 MBoeAcquisitions3,252 MBoeAcquisitions2,989 MBoeAcquisitions17,892 MBoeAcquisitions4,595 MBoe15,403 MBoe33,633 MBoe40,912 MBoe42,418 MBoe45,474 MBoe46,459 MBoe65,409 MBoe67,541 MBoe72,944 MBoe YE 2017 YE 2018 YE 2019 YE 2020 YE 2021 YE 2022 YE 2023 YE 2024 YE 2025
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202520242023202220212020201920182017201620151998 History 31 Kimbell has a strong track record of success as a natural consolidator in the mineral and royalty industry Closed Phillips acquisition from EnCap for $172 million in equity consideration; production nearly quadrupled since IPO With a handshake agreement in 1998, a small group of Fort Worth based investors laid the groundwork for what is now KimbellKimbell Royalty Partners, LP formedKimbell completed IPO1998October 2015February 2017 July 2018Closed acquisition of Haymaker assets for $444 million in cash and equity considerationDecember 2018Closed drop down acquisition for $90 million in equity considerationCompleted conversion to C-Corp for taxation purposes; completed follow-on equity offering September 2018March 2019April 2020Closed $123 million acquisition of mineral and royalty interests from Springbok for cash and equity considerationClosed $57 million acquisition of mineral and royalty interests from Cornerstone and completed the full redemption of Series A Preferred StockDecember 2021 Closed $271 million acquisition of mineral and royalty interests from Hatch for cash and equity considerationDecember 2022 May 2023Closed $141 million acquisition of mineral and royalty interests from MB Minerals for cash and equity considerationMB MineralsSeptember 2023Closed $455 million acquisition of mineral and royalty interests from LongPoint for cash consideration January 2025Closed $230 million acquisition of mineral and royalty interests from private seller for cash considerationPrivate Seller
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Defining a Net Royalty Acre 32 The calculation of a Net Royalty Acre differs across industry participantsKimbell 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 positionKimbell Acreage Under Both Methodologies(3)Net Mineral AcresRoyalty InterestNet Royalty AcresMany companies use a 1/8thconvention 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 belowNet Royalty AcresNet Royalty Acres (normalized to 1/8th) 1,266,824158,353(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 12/31/2025.
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33 Mineral Interests Generally Senior to All Claims in Capital StructureIn 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 revenueWorking Interest owner entitled to ~75-85% of production revenue and bears 100% of development cost and lease operating expenseSenior Secured DebtSenior DebtSubordinated DebtEquity
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Overview of Mineral & Royalty Interests 34 MineralsPerpetual real-property interests that grant oil and natural gas ownership under a tract of landRepresent 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 revenuesNPRIsNonparticipating royalty interestsRoyalty interests that are carved out of a mineral estatePerpetual right to receive a fixed cost-free percentage of production revenueDo not participate in upfront payments (i.e. lease bonus)ORRIsOverriding royalty interestsRoyalty interests that burden the working interests of a leaseRight to receive a fixed, cost-free percentage of production revenue (term limited to life of leasehold estate)Illustrative Mineral Revenue GenerationUnleased MineralsRevenue ShareKRP: 100%Operator: 0%Cost ShareKRP: 100%Operator: 0%Lease TerminationUpon termination of a lease, all future development rights revert to KRP to explore or lease againKRP Issues a LeaseKRP receives an upfront cash bonus payment and customarily a 20-25% royalty on production revenuesIn return, KRP delivers the right to explore and develop with the operator bearing 100% of costs for a specified lease termLeased MineralsRevenue ShareKRP: 20-25%Operator: 75-80%Cost ShareKRP: 0%Operator: 100%1234
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Positioned for Growth Through Acquisitions 35Source: EIA and Bloomberg.(1) Midpoint of market size estimate range. Based on production data from EIA and spot price as of 2/10/2026. 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.(2) Enterprise values of KRP, BSM and VNOM as of 2/10/2026. Sizing the Minerals MarketTotal Public Company Enterprise Value(2): <4%Market Opportunity: 96%Total Minerals Market Size(1): ~$657 billionAcquisitions from Current SponsorsConsolidation of Private Mineral CompaniesExisting 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~$657 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 companiesLack of scale is proving difficult for sponsors to monetize investments via IPOsKimbell is uniquely positioned to capitalize on private equity need for liquidity and value enhancement
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10.5%7.9%4.2%3.7%3.2%2.8% 2.8%KRP RoyaltyCo's Smid-Cap LiquidsE&PGas-Focused E&P US Majors Large-Cap LiquidsE&PMid-Cap LiquidsE&P Highest Dividend Yield Across U.S. Upstream Sector 36 Distribution/Dividend Yield Comparison Kimbell offers an attractive 10.5% distribution yield relative to the broader US upstream sector, and oil & gas mineral and royalty companies reflect compelling distribution yields compared to US E&Ps Source: Bloomberg as of 2/09/2026. RoyaltyCo: Average of VNOM, BSM and KRP cash distribution yield; US Majors include: CVX and XOM; Gas-Focused E&P include: EQT, EXE, NFG, RRC, and TXO; Large-Cap Liquids E&P: COP, EOG, FANG, and OXY; Mid-Cap Liquids: CTRA, DVN, OVV, and PR; SMID-Cap Liquids: APA, CHRD, CRGY, MGY, MTDR, SM, and NOG.
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Kimbell did not book any undeveloped reserves in its year-end 2025 reserve report included in its Form 10-K filed with the SECBased on the SPE-PRMS(1)reserve definitions, these undeveloped 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 approachKimbell only focused on its major properties and upside locations on minor properties were not identified. With ownership in over 17 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 15% to Kimbell’s net drilling inventory37 Kimbell Process & Methodology Process and Methodology (1) 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.(2) PUD, Probable, and Possible reserves reflect estimates from internal reserves database as of 12/31/2025.
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Historical Selected Financial Data 38 Non-GAAP Reconciliation (in thousands) (1) Consolidated Adjusted EBITDA for each of the quarters ended March 31, 2025, June 30, 2025 and September 30, 2025 was previously reported in a news release relating to the applicable quarter, and the reconciliation of net income to consolidated Adjusted EBITDA for each quarter is included in the applicable news release. This also includes the trailing twelve months pro forma results from the Q1 2025 acquisition that closed in January 2025 in accordance with Kimbell's secured revolving credit facility. Net income$ 24,804 Depreciation and depletion expense 31,935 Interest expense 9,119 Income tax benefit (1,304) Consolidated EBITDA$ 64,554 Unit-based compensation 4,170 Gain on derivative instruments, net of settlements (3,899) Consolidated Adjusted EBITDA $ 64,825 Q1 2025 - Q3 2025 Consolidated Adjusted EBITDA (1)203,233 Trailing Twelve Month Consolidated Adjusted EBITDA $ 268,058 Long-term debt (as of 12/31/25) 441,500 Cash and cash equivalents (as of 12/31/25) (43,977) Net debt (as of 12/31/25) $ 397,523 Net Debt to Trailing Twelve Month Consolidated Adjusted EBITDA 1.5x Three Months EndedDecember 31, 2025