VNOM 10-K & 10-Q changes, risk factors and insider trading

Pending Riverbend Acquisition

On MayJuly 1, 2026, we and Viper Energy Partners LP entered into a definitive purchase and sale agreement to acquireacquired all of the equity interests of Riverbend Oil & Gas IX, L.L.C., from Riverbend for consideration consisting of (i) approximately $337$339 million in cash, and (ii) 3,689,8653,691,796 shares of our Class A Common Stock, in each case, subject to customary closingpost-closing adjustments. The mineral and royalty interests to be acquired in the Pending Riverbend Acquisition represent approximately 3,0642,772 net royalty acres in the Permian Basin. The Pending Riverbend Acquisition is expected to close during the third quarter of 2026, subject to customary closing conditions. See Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for additional information on the Pending Riverbend Acquisition.

2026 Secondary Offering

AtAs Marchof 31,July 1, 2026, after giving effect to the Riverbend Acquisition, our footprint of mineral and royalty interests totaled approximately 86,63990,212 net royalty acres, approximately 38% of which are operated by Diamondback. See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for additional information on our acquisitions and divestitures.

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 conditionsconditions, 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 lastMiddle quarterEast, in 2026 the global crude oil market has shifted from abetween supply-demand surplussurpluses and deficits, due to amaterial deficit,reductions materially reducingin crude oil and refined products from the markets, andcreating increasingadditional volatility in benchmark crude oil prices. These factors are beyond our control and are difficult to predict. OPEC+ continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels and can heavily influence volatility in oil prices. During the threefirst monthshalf endedof March 31, 2026,2026 and 2025, WTI prices averaged $72.67$83.00 and $71.42$70.81 per Bbl, respectively, and Henry Hub prices averaged $3.47$3.20 and $3.87$3.69 per MMBtu, respectively.

As of MarchJuly 31,1, 2026, after giving effect to the Riverbend Acquisition, there were 88106 gross rigs operating on our mineral and royalty acreage, 1312 of which are operated by Diamondback. We delivered a strong startproduction toresults in the first half of 2026, withhighlighted firstby quartersteady productiondevelopment exceedingactivity expectationsfrom both Diamondback and anour increasedthird-party growthoperators outlookacross forour thehigh-quality remainderasset base, as well as a continuation of 2026.our Withdifferentiated theacquisition Pendingstrategy. RiverbendReflecting Acquisition,this momentum, we continueare increasing our strategy to consolidate the highly fragmented minerals and royalty sector. Currently, excluding the Pending Riverbend Acquisition, we estimate full year 2026 production levelsguidance in 2026 mayto range between approximately 126132.5 MBOE/d to 130135 MBOE/d.

The following table summarizes our gross well information foras of July 1, 2026, after giving effect to the firstRiverbend quarter ended March 31, 2026Acquisition:

(1)Average lateral length ofnormalized 11,583to 10,000 feet.

Comparison of the Three Months Ended MarchJune 31,30, 2026, and DecemberMarch 31, 20252026

Significant changes in our revenues and expenses between the firstsecond quarter of 2026 and the fourthfirst quarter of 20252026 are discussed further below.

Royalty income increased by $74$162 million during the firstsecond quarter of 2026 compared to the fourthfirst quarter of 2025.2026. This net increase consisted of an additional $91$152 million in royalty income attributable to higher average commodity prices received primarily for our oil productionproduction, inand thean firstadditional quarter of 2026 compared to the fourth quarter of 2025, partially offset by a reduction of $17$10 million due to a 5%4% decreaseincrease in our production.

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. Production taxes and adAd valorem taxes as a percentage of royalty income fordecreased in the firstsecond quarter of 2026 weredue relativelyprimarily consistentto withcurrent thevaluations fourthreflecting quarterlower of2025 2025.commodity prices.

The $5$18 million decrease in the gain on derivative instruments, net in the firstsecond quarter of 2026 compared to the fourthfirst quarter of 20252026 consisted primarilylargely of (i) a reduction of approximately $9$32 million in the value of our open oil contracts, (ii) a gain of approximately $7 million on our 2026 WTI Contingent Liability recorded in the fourth quarter of 2025, and (iii) a reduction of approximately $3 million 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.Hub, and an additional $7 million in cash paid to settle oil contracts. These decreases in the gain on derivative instrumentsreductions were partially offset by an increase of approximately $12$18 million in cashthe receiptsvalue of our open oil contracts primarily due to a decrease in market prices compared to contract prices on settledour natural gas basis swaps,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 $49$44 million changeincrease toin 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 taxattributable benefitto Viper and changes to the estimated deferred taxes recognized in connection with the fourth quarterclosing of 2025 was primarily driven by the $408Sitio million non-cash impairment recorded in the fourth quarter of 2025.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 change to $118$71 million increase in net income attributable to non-controlling interest for the second quarter of 2026 compared to the first quarter of 2026 from a net loss attributable to non-controlling interest of $143 million in the fourth quarter of 2025 was primarily due to (i)an the $408 million non-cash impairment recordedincrease in thepre-tax fourthincome, quarterslightly ofoffset 2025, and (ii)by a dilution of the non-controlling interest following the 2026 Secondary Offering.

Comparison of the ThreeSix Months Ended MarchJune 31,30, 2026, and 2025

Significant changes in our revenues and expenses for the threesix months ended MarchJune 31,30, 2026, as compared to the threesix months ended MarchJune 31,30, 2025, are discussed further below.

Royalty income increased $252$623 million during the threesix months ended MarchJune 31,30, 2026, compared to the same period in 2025. This net increase was primarilycomprised due toof an additional $282$444 million in royalty income from the 128%94% growth in production,production partially offset byand a net decreaseincrease of $30$179 million primarily from lowerhigher average natural gas and natural gas liquidsoil prices received for our production during the firstsix quartermonths ofended June 30, 2026 compared to the same period in 2025.

OfApproximately 59% of the 128% growth in production, approximately 54%production was attributable to the Sitio Acquisition and 45%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.

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. Production taxes and adAd valorem taxes as a percentage of royalty income for the threesix months ended MarchJune 31,30, 2026,2026 weredecreased relativelyslightly consistent withfrom the same period in 2025.2025 due primarily to current valuations reflecting lower 2025 commodity prices.

Depletion.Depreciation, Depletion, and Amortization. The $210 million increase in depletiondepreciation, depletion, and amortization expense of $139 million for the threesix months ended MarchJune 31,30, 2026, compared to the same period in 2025 consisted primarily of (i) $86$179 million from growth in production volumes, and (ii) $53$31 million due to an increase in the depletion rate to $17.51$16.71 per BOE for the threesix months ended MarchJune 31,30, 2026,2026 resultingcompared 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 comparedand topartially $12.97offset per BOE forby the same perioddecline in the depletion rate following the ceiling test impairment from the third and fourth quarters of 2025.

Interest Expense, Net. The increase in interestInterest expense, net ofincreased $14$23 million for the threesix months ended MarchJune 31,30, 2026, compared to the same period in 2025 consisted primarily ofdue to (i) approximately $22$44 million in additional expense incurred for our Guaranteed Senior Notes, and (ii) approximately $3 million in additional interest expense incurred on the Term Loan prior to its termination, and (iii) a reductiondecrease of approximately $3$5 million in interest income.income, These increases in interest expense, netwhich were partially offset by interest cost savings of approximately $13$26 million due to the early termination of the Notes.

The $14$15 million decreaseincrease in the gain on derivative instruments, net for the threesix months ended MarchJune 31,30, 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 $14$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,Hub on our basis swaps, and (iiiii) aother reductioninsignificant changes. See Note 10—Derivatives of approximatelythe $9notes million into the valuecondensed consolidated financial statements for additional discussion of our open oilcontracts contracts,at andJune (iii)30, an increase of approximately $2 million in cash paid to settle oil contracts. These decreases in the gain on derivative instruments were partially offset by an increase of approximately $13 million in cash receipts on settled natural gas basis swaps and other insignificant changes.2026.

Provision for (Benefit from) Income Taxes. The $7$72 million increase in income tax expense for the threesix months ended MarchJune 31,30, 2026, compared to the same period in 2025 primarily resulted from an increase in pre-tax income attributable to Viper.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 $40$182 million increase in net income attributable to non-controlling interest for the threesix months ended MarchJune 31,30, 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.

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. OurHistorically, 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. At March 31, 2026, we had $1.51 billion of liquidity consisting of $28 million in cash and cash equivalents and $1.48 billion in available borrowings under our Revolving Credit Facility. See “—Capital Resources” below for additional discussions of changes in our sources of cash.

Our working capital requirements are supported by our cash and cash equivalents and our Revolving Credit Facility. 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 including dividends, debt service obligations, repayment of debt maturities, any repurchases of our Common Stock, OpCo Units or Guaranteed Senior Notes and any amounts that may ultimately be paid in connection with contingencies.requirements.

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 oiloil, natural gas and natural gas liquids sold by our operators. The increase in net cash provided by operating activities during the threesix months ended MarchJune 31,30, 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.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.

Net cash provided by investing activities during the threesix months ended MarchJune 31,30, 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 threesix months ended MarchJune 31,30, 2025, was primarily related to acquisitions of oil and natural gas properties and a $223 million escrow deposit made forin the 2025 Drop Down.Down and from other third parties.

Net cash used in financing activities during the threesix months ended MarchJune 31,30, 2026, was primarily attributable to (i) $500 million paid for the retirement of the Term Loan, (ii) $213$494 million of dividends and dividend equivalent rights paid to holders of our OpCo Units and our Class A Common Stock, (iii) $96$228 million of securities repurchases under our repurchase program, and (iv) repayments, net repayments of $85borrowings, of $10 million on our Revolving Credit Facility.

Net cash provided by financing activities during the threesix months ended MarchJune 31,30, 2025, was primarily attributable to proceeds of $1.2 billion from the 2025 Equity Offering,Offering partially offset byand net repaymentsborrowings of $261$64 million on our Revolving Credit FacilityFacility. andThese $153cash inflows were partially offset by $345 million of dividends paid to holders of our OpCo Units and our Class A Common Stock.Stock and $50 million paid for the redemption of principal outstanding on certain senior notes.

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 MayJuly 1,31, 2026, we have repurchased an aggregate of 18,768,25722,315,760 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 $610$766 million, excluding any applicable excise tax, leaving approximately $1.14$984 billionmillion 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.

FirstSecond Quarter 2026 Cash Dividends and Return of Capital Update

The Operating Company will pay a cash distributiondividend for the firstsecond quarter of 2026 in accordance with its distribution policy of $0.86$0.97 per OpCo Unit on MayAugust 21,20, 2026, to eligible holders of record at the close of business on MayAugust 14,13, 2026.

Our capital‑light business model and high free cash flow margins positioned us to further deliver on our comprehensive capital allocation strategy. As a result, inIn addition to repurchases under our repurchase program, we will pay a cash dividend for the firstsecond quarter of 2026 of $0.68$0.67 per share of Class A Common Stock payable on MayAugust 21,20, 2026, to eligible holders of record at the close of business on MayAugust 14,13, 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 $0.30$0.29 per share of Class A Common Stock.

We expect to continue paying quarterly cash dividends in respect of our Class A Common Stock and OpCo Units. FutureHowever, 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 variablepursue 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.

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.