The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Part II. Item 1A. Risk Factors, Part I. Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2025 and Cautionary Statement Regarding Forward-Looking Statements. Overview We are a publicly traded Delaware corporation focused on owning and acquiring mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment. Recent Developments Pending 2026 Drop Down On August 3, 2026, we, as parent, and Viper Energy Partners LP, as buyer, entered into a definitive purchase agreement to acquire certain mineral and royalty interests from Diamondback and related subsidiaries in exchange for 3,654,979 OpCo Units and an equivalent number of shares of our Class B Common Stock, subject to transaction costs and certain customary post-closing adjustments. The mineral and royalty interests to be acquired in the Pending 2026 Drop Down represent approximately 933 net royalty acres in the Permian Basin. After giving effect to the Pending 2026 Drop Down, we currently estimate that following the closing of the Pending 2026 Drop Down, Diamondback will beneficially own approximately 39.8% of our outstanding Common Stock, on a fully diluted basis. Cash Dividend and Return of Capital Update On July 30, 2026, our board of directors approved an increase of 32% to our annual base dividend, or an amount equal to $2.00 per share of Class A Common Stock beginning with the dividend payable for the third quarter of 2026. With this increase and a commitment to grow the base dividend steadily over time, we are removing our commitment to return at least 75% of cash available for distribution each quarter. We believe a single, durable and growing base dividend, rather than a variable payout that fluctuates with commodity prices, best showcases what differentiates Viper: an industry-leading, low-breakeven yield paired with consistent per-share growth. Riverbend Acquisition On July 1, 2026, we and Viper Energy Partners LP acquired all of the equity interests of Riverbend Oil & Gas IX, L.L.C., from Riverbend for consideration consisting of (i) approximately $339 million in cash, and (ii) 3,691,796 shares of our Class A Common Stock, in each case, subject to customary post-closing adjustments. The mineral and royalty interests acquired in the Riverbend Acquisition represent approximately 2,772 net royalty acres in the Permian Basin. 2026 Secondary Offering On March 4, 2026, we completed the 2026 Secondary Offering, which authorized the Selling Stockholders to sell an aggregate of (i) 17,391,304 shares of Class A Common Stock, and (ii) up to an additional 2,608,696 shares of Class A Common Stock at the public offering price of $45.90. On March 19, 2026, the Underwriters exercised a portion of the Underwriter Option and purchased an additional 954,809 shares of Class A Common Stock. We did not receive any proceeds from the 2026 Secondary Offering or the Shoe Exercise. Divestiture of Non-Permian Assets On February 9, 2026, we completed the Non-Permian Divestiture for net cash proceeds of approximately $610 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with then-current production of approximately 4,750 BO/d. Proceeds from the Non-Permian Divestiture were used to (i) repay the $500 million Term Loan in full, (ii) fully repay $90 million of then-outstanding borrowings under our Revolving Credit Facility, and (iii) for general corporate purposes. 21 Table of Contents As of July 1, 2026, after giving effect to the Riverbend Acquisition, our footprint of mineral and royalty interests totaled approximately 90,212 net royalty acres, approximately 38% of which are operated by Diamondback. See Note 4—Acquisitions and Divestitures and Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for additional information on our acquisitions and divestitures and cash dividend and return of capital update. Commodity Prices Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Geopolitical global conflicts, tariffs or other trade barriers and any resulting trade tensions, regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, extreme weather conditions, changes in OPEC+ production levels and other substantially variable factors influence market conditions for these products. For example, as a result of the ongoing conflict in the Middle East, in 2026 the global crude oil market has shifted between supply-demand surpluses and deficits, due to material reductions in crude oil and refined products from the markets, creating additional volatility in benchmark crude oil prices. These factors are beyond our control and are difficult to predict. During the first half of 2026 and 2025, WTI prices averaged $83.00 and $70.81 per Bbl, respectively, and Henry Hub prices averaged $3.20 and $3.69 per MMBtu, respectively. Production and Operational Update As of July 1, 2026, after giving effect to the Riverbend Acquisition, there were 106 gross rigs operating on our mineral and royalty acreage, 12 of which are operated by Diamondback. We delivered strong production results in the first half of 2026, highlighted by steady development activity from both Diamondback and our third-party operators across our high-quality asset base, as well as a continuation of our differentiated acquisition strategy. Reflecting this momentum, we are increasing our full year 2026 production guidance to range between approximately 132.5 MBOE/d to 135 MBOE/d. The following table summarizes our gross well information as of July 1, 2026, after giving effect to the Riverbend Acquisition: Diamondback Operated Third-Party Operated Total Q2 2026 horizontal wells turned to production(1): Gross wells 146 545 691 Net 100% royalty interest wells 10.2 9.6 19.8 Average percent net royalty interest 7.0 % 1.8 % 2.9 % Horizontal producing well count(1): Gross wells 4,485 21,075 25,560 Net 100% royalty interest wells 277.7 322.9 600.6 Average percent net royalty interest 6.2 % 1.5 % 2.3 % Horizontal active development well count(1)(2): Gross wells 333 1,465 1,798 Net 100% royalty interest wells 21.9 17.2 39.1 Average percent net royalty interest 6.6 % 1.2 % 2.2 % Line of sight wells(1)(3): Gross wells 282 1,307 1,589 Net 100% royalty interest wells 16.3 16.6 32.9 Average percent net royalty interest 5.8 % 1.3 % 2.1 % (1)Average lateral length normalized to 10,000 feet. 22 Table of Contents (2)The total 1,798 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months. (3)The total 1,589 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices. Results of Operations Comparison of the Three Months Ended June 30, 2026, and March 31, 2026 The following table summarizes our income and expenses for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 (In millions) Operating income: Oil income $ 582 $ 428 Natural gas income 1 16 Natural gas liquids income 75 52 Royalty income 658 496 Lease bonus income 11 14 Lease bonus income—related party 4 1 Other operating income 4 — Total operating income 677 511 Costs and expenses: Production and ad valorem taxes 43 35 Depreciation, depletion, and amortization 195 206 General and administrative expenses 5 8 General and administrative expenses—related party 6 5 Other operating expenses — 4 Total costs and expenses 249 258 Income (loss) from operations 428 253 Other income (expense): Interest expense, net (24) (27) Gain (loss) on derivative instruments, net — 18 Other income (expense), net (1) (1) Total other income (expense), net (25) (10) Income (loss) before income taxes 403 243 Provision for (benefit from) income taxes 72 28 Net income (loss) 331 215 Net income (loss) attributable to non-controlling interest 189 118 Net income (loss) attributable to Viper Energy, Inc. $ 142 $ 97 23 Table of Contents The following table summarizes our production data, average sales prices and average costs for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 Production data: Oil (MBbls) 5,922 5,850 Natural gas (MMcf) 18,949 18,088 Natural gas liquids (MBbls) 3,147 2,899 Combined volumes (MBOE)(1) 12,227 11,764 Average daily oil volumes (BO/d) 65,077 65,000 Average daily combined volumes (BOE/d) 134,363 130,711 Average sales price: Oil ($/Bbl) $ 98.28 $ 73.16 Natural gas ($/Mcf) $ 0.05 $ 0.88 Natural gas liquids ($/Bbl) $ 23.83 $ 17.94 Combined ($/BOE)(2) $ 53.82 $ 42.16 Oil, hedged ($/Bbl)(3) $ 96.42 $ 72.31 Natural gas, hedged ($/Mcf)(3) $ 1.48 $ 2.27 Natural gas liquids ($/Bbl)(3) $ 23.83 $ 17.94 Combined price, hedged ($/BOE)(3) $ 55.12 $ 43.86 Average costs ($/BOE): Production and ad valorem taxes $ 3.52 $ 2.98 General and administrative - cash component 0.65 0.94 Total operating expense - cash $ 4.17 $ 3.92 General and administrative - non-cash stock compensation expense $ 0.25 $ 0.17 Interest expense, net $ 1.96 $ 2.30 Depreciation, depletion, and amortization $ 15.95 $ 17.51 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. (2)Realized price net of all deducts for gathering, transportation and processing. (3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices. Significant changes in our revenues and expenses between the second quarter of 2026 and the first quarter of 2026 are discussed further below. Royalty Income. Our royalty income is a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. Royalty income increased by $162 million during the second quarter of 2026 compared to the first quarter of 2026. This net increase consisted of an additional $152 million attributable to higher average commodity prices received primarily for our oil production, and an additional $10 million due to a 4% increase in our production. The 4% increase in production was largely attributable to having one additional day of production in the second quarter of 2026 compared to the first quarter of 2026 and new wells added during the second quarter. 24 Table of Contents Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 Amount (In millions) Per BOE Percentage of Royalty Income Amount (In millions) Per BOE Percentage of Royalty Income Production taxes $ 34 $ 2.78 5.2 % $ 26 $ 2.21 5.3 % Ad valorem taxes 9 0.74 1.3 9 0.77 1.8 Total production and ad valorem taxes $ 43 $ 3.52 6.5 % $ 35 $ 2.98 7.1 % In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes as a percentage of royalty income decreased in the second quarter of 2026 due primarily to current valuations reflecting lower 2025 commodity prices. Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization expense decreased by $11 million in the second quarter of 2026 compared to the first quarter of 2026. Approximately $19 million of the net decrease stemmed from a reduction in the depletion rate to $15.95 per BOE in the second quarter compared to $17.51 per BOE in the first quarter primarily due to an increase in reserve volumes as more wells remained economical longer at the higher SEC Prices applied in the second quarter. This was partially offset by an $8 million increase from growth in production volumes. Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented: Three Months Ended June 30, 2026 March 31, 2026 (In millions) Gain (loss) on derivative instruments, net $ — $ 18 Net cash receipts (payments) on derivatives $ 16 $ 20 The $18 million decrease in the gain on derivative instruments, net in the second quarter of 2026 compared to the first quarter of 2026 consisted largely of a $32 million reduction in the value of our open natural gas basis swap contracts primarily due to changes in the differential between prices for Waha Hub and Henry Hub, and an additional $7 million in cash paid to settle oil contracts. These reductions were partially offset by an increase of approximately $18 million in the value of our open oil contracts primarily due to a decrease in market prices compared to contract prices on our puts and roll swaps as well as other insignificant changes. See Note 10—Derivatives of the notes to the condensed consolidated financial statements for additional discussion of our open contracts at June 30, 2026. Provision for (Benefit from) Income Taxes. The $44 million increase in income tax expense in the second quarter of 2026 compared to the first quarter of 2026 primarily resulted from an increase in pre-tax income attributable to Viper and changes to the estimated deferred taxes recognized in connection with the closing of the Sitio Acquisition. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of income tax expense. Net Income (Loss) Attributable to Non-Controlling Interest. The $71 million increase in net income attributable to non-controlling interest for the second quarter of 2026 compared to the first quarter of 2026 was primarily due to an increase in pre-tax income, slightly offset by a dilution of the non-controlling interest following the 2026 Secondary Offering. 25 Table of Contents Comparison of the Six Months Ended June 30, 2026, and 2025 The following table summarizes our income and expenses for the periods indicated: Six Months Ended June 30, 2026 2025 (In millions) Operating income: Oil income $ 1,010 $ 442 Natural gas income 17 25 Natural gas liquids income 127 64 Royalty income 1,154 531 Lease bonus income 25 11 Lease bonus income—related party 5 — Other operating income 4 — Total operating income 1,188 542 Costs and expenses: Production and ad valorem taxes 78 38 Depreciation, depletion, and amortization 401 191 General and administrative expenses 13 6 General and administrative expenses—related party 11 7 Other operating expenses 4 10 Total costs and expenses 507 252 Income (loss) from operations 681 290 Other income (expense): Interest expense, net (51) (28) Gain (loss) on derivative instruments, net 18 3 Other income (expense), net (2) — Total other income (expense), net (35) (25) Income (loss) before income taxes 646 265 Provision for (benefit from) income taxes 100 28 Net income (loss) 546 237 Net income (loss) attributable to non-controlling interest 307 125 Net income (loss) attributable to Viper Energy, Inc. $ 239 $ 112 26 Table of Contents The following table summarizes our production data, average sales prices and average costs for the periods indicated: Six Months Ended June 30, 2026 2025 Production data: Oil (MBbls) 11,772 6,605 Natural gas (MMcf) 37,037 17,353 Natural gas liquids (MBbls) 6,046 2,881 Combined volumes (MBOE)(1) 23,991 12,378 Average daily oil volumes (BO/d) 65,039 36,492 Average daily combined volumes (BOE/d) 132,547 68,387 Average sales prices: Oil ($/Bbl) $ 85.80 $ 66.92 Natural gas ($/Mcf) $ 0.46 $ 1.44 Natural gas liquids ($/Bbl) $ 21.01 $ 22.21 Combined ($/BOE)(2) $ 48.10 $ 42.90 Oil, hedged ($/Bbl)(3) $ 84.44 $ 66.01 Natural gas, hedged ($/Mcf)(3) $ 1.86 $ 2.48 Natural gas liquids ($/Bbl)(3) $ 21.01 $ 22.21 Combined price, hedged ($/BOE)(3) $ 49.60 $ 43.87 Average costs ($/BOE): Production and ad valorem taxes $ 3.25 $ 3.07 General and administrative - cash component 0.79 0.81 Total operating expense - cash $ 4.04 $ 3.88 General and administrative - non-cash stock compensation expense $ 0.21 $ 0.24 Interest expense, net $ 2.13 $ 2.26 Depreciation, depletion, and amortization $ 16.71 $ 15.43 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. (2)Realized price net of all deducts for gathering, transportation and processing. (3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices. Significant changes in our revenues and expenses for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025, are discussed further below. Royalty Income. Our royalty income is a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. Royalty income increased $623 million during the six months ended June 30, 2026, compared to the same period in 2025. This net increase was comprised of an additional $444 million from the 94% growth in production and a net increase of $179 million primarily from higher average oil prices received for our production during the six months ended June 30, 2026 compared to the same period in 2025. 27 Table of Contents Approximately 59% of the growth in production was attributable to the Sitio Acquisition and 40% was attributable to the 2025 Drop Down. The remainder of the growth is primarily from new wells added between periods. See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for additional discussion of our acquisitions. Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated: Six Months Ended June 30, 2026 2025 Amount (In millions) Per BOE Percentage of Royalty Income Amount (In millions) Per BOE Percentage of Royalty Income Production taxes $ 60 $ 2.50 5.2 % $ 27 $ 2.18 5.1 % Ad valorem taxes 18 0.75 1.6 11 0.89 2.1 Total production and ad valorem taxes $ 78 $ 3.25 6.8 % $ 38 $ 3.07 7.2 % In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes as a percentage of royalty income for the six months ended June 30, 2026 decreased slightly from the same period in 2025 due primarily to current valuations reflecting lower 2025 commodity prices. Depreciation, Depletion, and Amortization. The $210 million increase in depreciation, depletion, and amortization expense for the six months ended June 30, 2026, compared to the same period in 2025 consisted primarily of (i) $179 million from growth in production volumes, and (ii) $31 million due to an increase in the depletion rate to $16.71 per BOE for the six months ended June 30, 2026 compared to $15.43 per BOE for the same period in 2025, primarily from the addition of leasehold costs and reserves from the 2025 Drop Down and the Sitio Acquisition and partially offset by the decline in the depletion rate following the ceiling test impairment from the third and fourth quarters of 2025. Interest Expense, Net. Interest expense, net increased $23 million for the six months ended June 30, 2026, compared to the same period in 2025 primarily due to (i) $44 million in additional expense incurred for our Guaranteed Senior Notes, and (ii) a decrease of $5 million in interest income, which were partially offset by interest cost savings of approximately $26 million due to the early termination of the Notes. Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented: Six Months Ended June 30, 2026 2025 (In millions) Gain (loss) on derivative instruments, net $ 18 $ 3 Net cash receipts (payments) on derivatives $ 36 $ 12 The $15 million increase in the gain on derivative instruments, net for the six months ended June 30, 2026, compared to the same period in 2025 consisted primarily of $33 million in additional cash receipts on settled natural gas basis swaps, partially offset by (i) $10 million in additional cash paid to settle oil contracts, (ii) a reduction of approximately $7 million in the value of our open natural gas contracts due primarily to changes in the differential between prices for Waha Hub and Henry Hub on our basis swaps, and (iii) other insignificant changes. See Note 10—Derivatives of the notes to the condensed consolidated financial statements for additional discussion of our open contracts at June 30, 2026. Provision for (Benefit from) Income Taxes. The $72 million increase in income tax expense for the six months ended June 30, 2026, compared to the same period in 2025 primarily resulted from an increase in pre-tax income attributable to Viper and changes to the estimated deferred taxes recognized in connection with the closing of the Sitio Acquisition. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of income tax expense. 28 Table of Contents Net Income (Loss) Attributable to Non-Controlling Interest. The $182 million increase in net income attributable to non-controlling interest for the six months ended June 30, 2026, compared to the same period in 2025 was primarily due to (i) an increase in net income, and (ii) changes in the non-controlling interest in the Operating Company resulting from the Drop Down Equity Issuance and the issuance of OpCo Units to fund the Sitio Acquisition, which were partially offset by a dilution of the non-controlling interest following the 2025 Equity Offering and the 2026 Secondary Offering. Liquidity and Capital Resources Overview of Sources and Uses of Cash As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Historically, our primary sources of liquidity have been cash flow from operations, equity and debt offerings, borrowings under our Revolving Credit Facility, term loan agreements and proceeds from sales of non-core assets. Our primary uses of cash have been dividends to our stockholders, Operating Company distributions to the holders of OpCo Units, repayments of debt, capital expenditures for the acquisition of our mineral and royalty interests in oil and natural gas properties and repurchases of our Common Stock and OpCo Units. Our working capital requirements are supported by our cash and cash equivalents and our Revolving Credit Facility. At June 30, 2026, we had $1.99 billion of liquidity consisting of $77 million in cash and cash equivalents and $1.91 billion in available borrowings under our Revolving Credit Facility. See “—Capital Resources” below for additional discussions of changes in our sources of cash. We may draw on our Revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements. In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Note 10—Derivatives of the notes to the condensed consolidated financial statements. Cash Flows The following table presents our cash flows for the periods indicated: Six Months Ended June 30, 2026 2025 (In millions) Net cash provided by (used in) operating activities $ 815 $ 373 Net cash provided by (used in) investing activities 478 (1,260) Net cash provided by (used in) financing activities (1,229) 888 Net increase (decrease) in cash and cash equivalents $ 64 $ 1 Operating Activities Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volumes of oil, natural gas and natural gas liquids sold by our operators. The increase in net cash provided by operating activities during the six months ended June 30, 2026, compared to the same period in 2025 was primarily driven by an increase in royalty income, which was partially offset by (i) changes in our working capital accounts including the timing of when accounts receivable are collected and when payments are made on accounts payable, and (ii) an increase in certain cash payments, including for federal taxes, interest on our debt, and production and ad valorem taxes. See “—Results of Operations” for discussion of significant changes in our income and expenses. 29 Table of Contents Investing Activities Net cash provided by investing activities during the six months ended June 30, 2026, was primarily related to proceeds received from the Non-Permian Divestiture, partially offset by individually insignificant acquisitions of oil and natural gas properties. See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for additional information on these transactions. Net cash used in investing activities during the six months ended June 30, 2025, was primarily related to acquisitions of oil and natural gas properties in the 2025 Drop Down and from other third parties. Financing Activities Net cash used in financing activities during the six months ended June 30, 2026, was primarily attributable to (i) $500 million paid for the retirement of the Term Loan, (ii) $494 million of dividends and dividend equivalent rights paid to holders of our OpCo Units and our Class A Common Stock, (iii) $228 million of securities repurchases under our repurchase program, and (iv) repayments, net of borrowings, of $10 million on our Revolving Credit Facility. Net cash provided by financing activities during the six months ended June 30, 2025, was primarily attributable to proceeds of $1.2 billion from the 2025 Equity Offering and net borrowings of $64 million on our Revolving Credit Facility. These cash inflows were partially offset by $345 million of dividends paid to holders of our OpCo Units and our Class A Common Stock and $50 million paid for the redemption of principal outstanding on certain senior notes. Capital Resources The Revolving Credit Facility On June 12, 2026, the Company, as the parent guarantor, and VNOM Sub, Inc., as a guarantor, entered into a first amendment to the Revolving Credit Agreement with Viper Energy Partners LP, as borrower, the lenders and other guarantors named therein and Wells Fargo Bank, National Association, as administrative agent, which among other things, (i) increased the total commitments under the Revolving Credit Agreement from $1.50 billion to $2.00 billion, and (ii) extended the maturity date from June 12, 2030, to June 12, 2031. We had $95 million in outstanding borrowings and $1.91 billion of availability at June 30, 2026. See Note 6—Debt of the notes to the condensed consolidated financial statements for additional discussions of our debt. Capital Requirements Repurchases of Securities On December 10, 2025, our board of directors expanded the repurchase program to include repurchases of our Class B Common Stock and OpCo Units in addition to our previously authorized Class A Common Stock. On February 18, 2026, our board of directors also approved an increase in our repurchase program authorization from $750 million to $1.75 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022. Since the inception of our repurchase program through July 31, 2026, we have repurchased an aggregate of 22,315,760 shares of our Class A Common Stock and 2,000,000 shares of our Class B Common Stock and OpCo Units for a total cost of $766 million, excluding any applicable excise tax, leaving approximately $984 million for future repurchases under the repurchase program. See Note 7—Stockholders’ Equity of the notes to the condensed consolidated financial statements for further discussion of our stock repurchase program. Second Quarter 2026 Cash Dividends and Return of Capital Update The Operating Company will pay a cash dividend for the second quarter of 2026 in accordance with its distribution policy of $0.97 per OpCo Unit on August 20, 2026, to eligible holders of record at the close of business on August 13, 2026. In addition to repurchases under our repurchase program, we will pay a cash dividend for the second quarter of 2026 of $0.67 per share of Class A Common Stock payable on August 20, 2026, to eligible holders of record at the close of business on August 13, 2026. The dividend to stockholders consists of a base quarterly dividend of $0.38 per share of Class A Common Stock and a variable quarterly dividend of $0.29 per share of Class A Common Stock. 30 Table of Contents We expect to continue paying quarterly cash dividends in respect of our Class A Common Stock and OpCo Units. However, beginning in the third quarter of 2026, we intend to transition away from our commitment to return at least 75% of cash available for distribution each quarter, and will increase the annual base dividend to $2.00 per share of our Class A Common Stock, which annual dividend will be payable in quarterly installments of $0.50 per share of our Class A Common Stock. The flexibility created by retaining excess cash flow will allow us to continue to opportunistically repurchase shares, reduce debt and pursue a disciplined mergers and acquisitions strategy, all of which we expect to compound value for our stockholders over the long term. Future dividends on Class A Common Stock and stock repurchases are not required and are at the discretion of the board of directors, who may change the dividend policy and/or share repurchase program at any time. See Note 7—Stockholders’ Equity of the notes to the condensed consolidated financial statements for further discussion of the repurchase program and dividends. Supplemental Guarantor Disclosure The Guaranteed Senior Notes are fully and unconditionally guaranteed by each of Former Viper and New Viper. Following the Reorganization, Viper Energy Partners LP became the issuer of the Guaranteed Senior Notes. The Guaranteed Senior Notes and the guarantees are obligations of the issuer and the guarantors that (i) are senior unsecured obligations and rank equally in right of payment with all of their respective existing and future senior indebtedness, including obligations under the Revolving Credit Facility, (ii) rank senior in right of payment to any of their respective future indebtedness that is expressly subordinated in right of payment to the Guaranteed Senior Notes or the guarantees, as applicable, (iii) are effectively subordinated to any of their respective existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, and (iv) are structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of subsidiaries that are not obligors under the Guaranteed Senior Notes. In the event of bankruptcy, liquidation, reorganization or other winding up of the issuer or a guarantor or upon a default in payment with respect to, or the acceleration of, any senior secured indebtedness of the issuer or a guarantor, the assets that secure such senior secured indebtedness will be available to pay obligations on the Guaranteed Senior Notes and the guarantees only after all obligations under such senior secured indebtedness have been repaid in full from such assets. There may not be sufficient assets remaining to pay amounts due on any or all of the Guaranteed Senior Notes then outstanding and the guarantees. The obligations of the guarantors under the guarantees are limited in a manner designed to prevent the guarantees from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. If a guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including contingent liabilities) of such guarantor, and, depending on the amount of such indebtedness, the guarantor’s liability on such guarantee could be reduced to zero. In accordance with Rule 3-10 of Regulation S-X, subsidiary issuers of obligations guaranteed by the parent are not required to provide separate financial statements, provided that the subsidiary obligor is consolidated into the parent company’s condensed consolidated financial statements, the parent guarantee is “full and unconditional,” except that such guarantee will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, and, subject to certain exceptions, the alternative disclosures specified in Rule 13-01 are provided, which include narrative disclosure and summarized financial information. Accordingly, separate consolidated financial statements of the issuer have not been presented. Furthermore, as permitted under Rule 13-01(a)(4)(vi) of Regulation S-X, we have excluded the summarized financial information for the issuer because the assets, liabilities and results of operations of the issuer are not materially different than the corresponding amounts in our condensed consolidated financial statements and management believes such summarized financial information would be repetitive and would not provide incremental value to investors. Critical Accounting Estimates There have been no changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2025. Recent Accounting Pronouncements See Note 2—Summary of Significant Accounting Policies of the notes to the condensed consolidated financial statements for recent accounting pronouncements not yet adopted, if any. 31 Table of Contents