Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, geopolitical global conflicts, higher interest rates, effects of tariffs, actions taken by OPEC and its non-OPEC allies, known collectively as OPEC+, global supply chain disruptions, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of these events and changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves, including those acquired by the Company, and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third-party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties and estimates of income taxes, including deferred tax valuation allowances. Other areas requiring estimation include commodity derivatives and various fair values of non-oil and gas assets and liabilities.

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

The Company earns lease bonus income by leasing its mineral interests to exploration, development and production companies. The Company recognizes lease bonus income when a lease agreement has been executed and payment is determined to be collectible.

The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the operator of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts.

Under the Company’s royalty income contracts, it generally has the right to receive its interest in the gross proceeds collected by the operator from third-party purchasers of the Company’s production once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered. As a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s royalty interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the operator. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs from third parties are capitalized and amortized on a composite unit of production method based on proved oil, natural gas and natural gas liquids reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas and natural gas liquids. Acquisitions of mineral and royalty interests from related parties are typically recorded at the parent’s historical carrying value and related transaction costs are expensed as incurred in accordance with guidance in ASC 805 for transactions between entities under common control. At December 31, 2025, and 2024, the Company’s oil and natural gas properties consisted primarily of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.48, $11.77 and $10.20 for the years ended December 31, 2025, 2024 and 2023, respectively. Depletion for oil and natural gas properties was $607 million, $214 million and $146 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, (ii) the cost of properties not being amortized, if any, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5—Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property at least annually for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent of the operator to drill; remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the

assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Royalty income receivables consist of receivables for sales of oil, natural gas and natural gas liquids made by the Company’s third-party operators and Diamondback to third-party purchasers. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work, which is required to be completed by the operator before payments are released.

Royalty income receivables are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. Royalty income receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance utilizing the loss-rate method, which considers a number of factors, including the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific royalty income receivables when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2025 and 2024, the Company’s allowance for expected losses was immaterial.

The Company is subject to risk resulting from the concentration of its royalty income in producing oil and natural gas properties and receivables with several significant operators. For the year ended December 31, 2025, two operators each accounted for more than 10% of royalty income: Diamondback (55%) and ExxonMobil Corporation (14%). For the year ended December 31, 2024, two operators each accounted for more than 10% of royalty income: Diamondback (54%) and Pioneer Natural Resources (11%). For the year ended December 31, 2023, one operator accounted for more than 10% of royalty income: Diamondback (61%). Each of the Company’s operators sell to multiple purchasers. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

As of December 31, 2025 and 2024, Diamondback, either directly or through its consolidated subsidiaries, owed the Company $88 million and $31 million, respectively, for royalty income received from third parties for the Company’s production, which had not yet been remitted to the Company.

During the year ended December 31, 2025, Diamondback and its subsidiaries paid the Operating Company $24 million of lease bonus income for 18 new leases covering 2,356 acres in Dawson, Glasscock, Howard, Martin, Midland and Reagan Counties, Texas. Lease bonus income from Diamondback for the year ended December 31, 2024 was immaterial. During the year ended December 31, 2023, Diamondback and its subsidiaries paid the Operating Company $108 million of lease bonus income, which included (i) one new lease of $96 million covering certain acreage in our Spanish Trail prospect in Midland County, Texas, from a lease agreement with a subsidiary of Diamondback on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback and was considered and approved by the conflicts committee of the board of directors, (ii) nine other new leases covering 703 acres in Martin, Midland, Pecos, and Wheeler Counties, Texas, and (iii) two lease extensions covering 25 acres in Martin County, Texas.

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2025, 2024 and 2023, there were no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. See Note 9—Income Taxes for further details.

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, former equity holders of Sitio Royalties Operating Partnership, LP (“Sitio OpCo”), Tumbleweed Royalty IV, LLC (“TWR IV”) and the Morita Ranches Equity Recipients (as defined and discussed in Note 4—Acquisitions and Divestitures) in the net assets of the Operating Company. When the non-controlling interests’ relative ownership in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Company’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 7—Stockholders’ Equity for further discussion of changes in ownership interest.

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The- Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Other assets include capitalized costs related to our current credit facility, the previous credit facility and the Term Loan (as defined and discussed in Note 6—Debt) of $21 million and $18 million, and accumulated amortization of those costs over the term of the respective credit facilities of $13 million and $11 million as of December 31, 2025 and 2024, respectively.

Long-term debt includes capitalized costs related to the Guaranteed Senior Notes. The costs associated with the Guaranteed Senior Notes are netted against the Guaranteed Senior Notes’ balances and amortized over the term of the Guaranteed Senior Notes using the effective interest method. See Note 6—Debt for further details.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The Company adopted the amendments in 2025 and applied the guidance on a retrospective basis. Adoption of the update resulted in additional disclosures in Note 9—Income Taxe s but did not impact the Company’s financial position, results of operations or liquidity.

In September 2025, the FASB issued ASU 2025-07, “Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) – Derivatives Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract.” The ASU addresses (i) the application of derivative accounting to

contracts that include features based on the operations or activities of one of the parties to the contract and (ii) diversity in practice related to accounting for share-based noncash consideration from a customer. The Company elected to early-adopt this amendment in 2025 and applied the guidance on a prospective basis. Adoption of the update did not impact the Company’s historical financial position, results of operations or liquidity; however, the guidance may affect whether certain new arrangements qualify for derivative accounting.

In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses,” which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.