Viper Energy - 10-K annual report 2025

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-42807

Viper Energy, Inc.

(Exact name of registrant as specified in its charter)

39-2596878

State or other jurisdiction of incorporation or organization

(I.R.S. Employer Identification No.)

500 West Texas Ave.,

Suite 100

Midland,

79701

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code (432) 221-7400

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, $0.000001 Par Value

VNOM

The Nasdaq Stock Market LLC

(NASDAQ Global Select Market)

Securities registered pursuant to section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2025, was approximately $5.0 billion.

As of February 20, 2026, 176,723,281 shares of Class A Common Stock and 180,825,588 shares of Class B Common Stock of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Viper Energy, Inc.’s Proxy Statement for the 2026 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.

VIPER ENERGY, INC.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2025

TABLE OF CONTENTS


			Page
Glossary of Oil and Natural Gas Terms			ii
Glossary of Certain Other Terms			iv
Cautionary Statement Regarding Forward-Looking Statements			v

PART I
Items 1 and 2. Business and Properties			1
Item 1A. Risk Factors			14
Item 1B. Unresolved Staff Comments			25
Item 1C. Cybersecurity			25
Item 3. Legal Proceedings			26
Item 4. Mine Safety Disclosures			26

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. [Reserved]			28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			42
Item 8. Financial Statements and Supplementary Data			44
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			83
Item 9A. Controls and Procedures			83
Item 9B. Other Information			86
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			86

PART III
Item 10. Directors, Executive Officers and Corporate Governance			86
Item 11. Executive Compensation			86
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			86
Item 13. Certain Relationships and Related Transactions, and Director Independence			86
Item 14. Principal Accountant Fees and Services			86

PART IV
Item 15. Exhibits and Financial Statement Schedules			87
Item 16. Form 10-K Summary			89
Signatures			90

Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K (the “Annual Report” or this “report”):




Argus WTI Midland			Grade of oil that serves as a benchmark price for oil at Midland, Texas.
Basin			A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel			One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

BO			One barrel of crude oil.
BO/d			One BO per day.
BOE			One barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d			One BOE per day.

British Thermal Unit			The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion			The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate			Liquid hydrocarbons associated with the production that is primarily natural gas.
Crude oil			Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Deterministic method			The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage			Acreage allocated or assignable to productive wells.
Development costs			Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
Development well			A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Differential			An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole			A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploitation			A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field			An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding costs			Capital costs incurred in the acquisition of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Formation			A layer of rock which has distinct characteristics that differs from nearby rock.
Fracturing			The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross royalty acres or gross wells			The total acres or wells in which a mineral interest is owned.
Henry Hub			Natural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
Horizontal drilling			A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbls			One thousand barrels of crude oil and other liquid hydrocarbons.


MBOE			One thousand BOE, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MBOE/d			One thousand BOE per day.
Mcf			One thousand cubic feet of natural gas.

Mineral interests			The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu			One million British Thermal Units.
MMcf			Million cubic feet of natural gas.

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Net mineral acres			The portion of total mineral rights a person or entity owns in a tract of land, calculated by multiplying the gross royalty acres in such tract by such person or entity’s fractional ownership interest.
Net revenue interest			An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding interests and other burdens.
Net royalty acres			Net mineral acres multiplied by the average lease royalty interest and other burdens.
Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator			The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Plugging and abandonment			Refers to the sealing off of fluids in the reservoir penetrated by a well so that the fluids from one reservoir will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well			A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Prospect			A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercially recoverable hydrocarbons.
Proved developed reserves			Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves			The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves or PUDs			Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.


Recompletion			The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves			Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir			A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource play			A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Royalty interest			An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
Spacing			The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Spud			Commencement of actual drilling operations.
Standardized measure			The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Tight formation			A formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Undeveloped acreage			Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Waha Hub			Natural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.
Wellbore			The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
Working interest			An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI			West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil that serves as a benchmark for oil on the NYMEX.
WTI Cushing			Grade of oil that serves as a benchmark price for oil at Cushing, Oklahoma.

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms used in this report:


Adjusted EBITDA			Consolidated Adjusted EBITDA, a non-GAAP measure, generally equals net income (loss) attributable to Viper Energy, Inc. plus net income (loss) attributable to non-controlling interest before interest expense, net, non-cash share-based compensation expense, depletion, impairment, non-cash (gain) loss on derivative instruments, (gain) loss on extinguishment of debt, other non-cash operating expenses, other non-recurring expenses, if any, and provision for (benefit from) income taxes.
ASU			Accounting Standards Update.
Class A Common Stock			After August 19, 2025, Class A common stock, $0.000001 par value per share of New Viper (as defined below), and before August 19, 2025, Class A common stock, $0.000001 par value per share of Former Viper (as defined below).
Class B Common Stock			After August 19, 2025, Class B common stock, $0.000001 par value per share of New Viper, and before August 19, 2025, Class B common stock, $0.000001 par value per share of Former Viper.
Common Stock			Collectively, Class A Common Stock and Class B Common Stock.

Conversion			The transaction, effective November 13, 2023, whereby the Partnership converted from a Delaware limited partnership to a Delaware corporation known as “Viper Energy, Inc.”
Diamondback			Diamondback Energy, Inc., a Delaware corporation.
Diamondback E&P LLC			A subsidiary of Diamondback.
EPA			United States Environmental Protection Agency.
Exchange Act			The Securities Exchange Act of 1934, as amended.
FASB			Financial Accounting Standards Board.
FERC			Federal Energy Regulatory Commission.
GAAP			Accounting principles generally accepted in the United States.
General Partner			Viper Energy Partners GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly owned subsidiary of Diamondback prior to the Conversion.
Guaranteed Senior Notes			The outstanding senior notes of Viper Energy Partners LP (f/k/a Viper Energy Partners LLC), issued under indentures where Viper Energy, Inc. and VNOM Sub, Inc., a wholly owned subsidiary of Viper Energy, Inc., are the guarantors, consisting of the 4.900% Senior Notes due 2030 and the 5.700% Senior Notes due 2035.




LTIP			Viper Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended and restated by Viper Energy, Inc. 2024 Amended and Restated Long-Term Incentive Plan, and as may be further amended or restated from time to time.
Nasdaq			The Nasdaq Global Select Market.
Net debt			Net debt, a non-GAAP measure, is debt (excluding debt issuance costs, discounts and premiums) less cash and cash equivalents.
Notes			Those senior notes of Viper Energy, Inc. that were issued under indentures where Viper Energy Partners LLC and other subsidiaries were guarantors, consisting of the 5.375% Senior Notes due 2027 and the 7.375% Senior Notes due 2031, and which were redeemed on November 1, 2025 and July 23, 2025, respectively.
NYMEX			New York Mercantile Exchange.
OPEC			Organization of the Petroleum Exporting Countries.
Operating Company or OpCo			Prior to December 23, 2025, Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy, Inc. and after December 23, 2025, VNOM Holding Company LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy, Inc.
OpCo Unit			Limited liability company membership interest in the Operating Company.

Partnership			Viper Energy Partners LP, the predecessor of the Company (as defined below), which converted into the Company in the Conversion.
Partnership Agreement			The second amended and restated agreement of limited partnership of the Partnership, dated as of May 9, 2018, as amended as of May 10, 2018, and further amended on November 2, 2023.
Ryder Scott			Ryder Scott Company, L.P.

SEC			United States Securities and Exchange Commission.
SEC Prices			Unweighted arithmetic average of the first-day-of-the-month price for each month during the 12-month period prior to the ending date of the period covered by this report.
Securities Act			The Securities Act of 1933, as amended.
SOFR			The secured overnight financing rate.
Wells Fargo			Wells Fargo Bank, National Association.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow and financial position; production levels on properties in which we have mineral and royalty interests; developmental activity by other operators; reserve estimates and our ability to replace or increase reserves; anticipated benefits or other effects of strategic transactions; and plans and objectives of management (including Diamondback’s plans for developing our acreage, our cash dividend policy and repurchases of our Common Stock, OpCo Units or Guaranteed Senior Notes) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to us are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although we believe that the expectations and assumptions reflected in our forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond our control. Accordingly, forward-looking statements are not guarantees of our future performance and the actual outcomes could differ materially from what we expressed in our forward-looking statements.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following:

•changes in supply and demand levels for oil, natural gas and natural gas liquids and the resulting impact on the price for those commodities;

•the impact of public health crises, including epidemic or pandemic diseases and any related company or government policies or actions;

•actions taken by the members of OPEC and its non-OPEC allies (“OPEC+”) affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;

•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates, or instability in the financial sector;

•regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;

•physical and transition risks relating to climate change and changing political and social perspectives on climate change and other ESG (as defined below) factors;

•risks from our cash dividend policy and uncertainties over our future dividends;

•restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;

•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;

•changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions;

•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our limited number of operators and our ability to replace operators in time of bankruptcy or default;

•changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators;

•the inherent uncertainties over our estimated reserves, the development of our proved undeveloped reserves or the yield from project areas on our properties;

•the geographical concentration of our producing properties and reserves in the Permian Basin and in a small number of producing horizons;

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•changes in safety, health, environmental, tax and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change);

•security threats, including cybersecurity threats and disruptions to our business from breaches of Diamondback’s information technology systems, or from breaches of information technology systems of our operators or third parties with whom we transact business;

•lack of, or disruption in, access to adequate and reliable electrical power, internet and telecommunication infrastructure, information and computer systems, transportation, processing, storage and other facilities impacting our operators;

•severe weather conditions and natural disasters;

•geopolitics, regional conflicts, acts of war or terrorist acts and the governmental or military response thereto;

•changes in the financial strength of counterparties to the credit facility and hedging contracts of our operating subsidiary;

•our substantial indebtedness and changes in our credit rating;

•failure to develop or acquire additional reserves and identify, complete or integrate acquisitions;

•our operational dependence on, and control by, Diamondback and potential conflicts of interest thereof; and

•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.

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PART I

On November 13, 2023, Viper Energy Partners LP converted from a Delaware limited partnership to a Delaware corporation named “Viper Energy, Inc.” (the “Conversion”).

On August 19, 2025, upon completion of the Sitio Acquisition (as defined and discussed below), Viper Energy, Inc. changed its name to VNOM Sub, Inc. (“Former Viper”) and became a wholly owned subsidiary of New Cobra Pubco, Inc., which subsequently changed its name to Viper Energy, Inc., (“New Viper”), as a result of a merger contemplated by the documents governing the Sitio Acquisition (such merger, the “Viper PubCo Merger”).

On December 23, 2025, the Company completed an internal reorganization (the “Reorganization”), pursuant to which, among other things, each outstanding OpCo Unit of Viper Energy Partners LLC, a Delaware limited liability company and Viper’s operating subsidiary (“Old OpCo”), was converted into an equivalent OpCo Unit issued by a newly-formed subsidiary of Viper, VNOM Holding Company LLC (“New OpCo”).

References in this Annual Report to “Viper” refer to (A) New Viper following the Viper PubCo Merger (B) Former Viper prior to the Viper PubCo Merger but after the Conversion, and (C) Viper Energy Partners LP prior to the Conversion. References to the “Company,” “our company,” “we,” “our,” “us” or like terms refer collectively to Viper and its consolidated subsidiaries. References to “shares” or per share amounts prior to the Conversion refer to common units and Class B units or per unit amounts of Viper Energy Partners LP. References to shares or per share amounts following the Conversion refer to (A) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of New Viper following the Viper PubCo Merger and (B) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of Former Viper prior to the Viper PubCo Merger.

References to the “Operating Company” or “OpCo” refer to (A) New OpCo following the Reorganization and (B) Old OpCo prior to the Reorganization. References to “OpCo Units” refer to the units representing limited liability company interests in the Operating Company.

References to “Diamondback” refer collectively to Diamondback Energy, Inc. and its subsidiaries other than the Company. References to the “General Partner” refer to Viper Energy Partners GP LLC, our general partner prior to the Conversion. All references to dividends prior to the Conversion refer to distributions.

See Note 1—Organization and Basis of Presentation in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of the Conversion.

ITEMS 1 and 2. BUSINESS AND PROPERTIES

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. Effective November 13, 2023, we converted our legal status from a Delaware limited partnership into a Delaware corporation. Our primary business objective is to provide an attractive return to our stockholders by focusing on business results, generating robust free cash flow, reducing debt and protecting our balance sheet, while maintaining what we believe is a best-in-class cost structure. Our assets consist of mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin in West Texas, substantially all of which are leased to working interest owners who bear the costs of operation and development.

We are currently focused on oil and natural gas properties primarily in the Permian Basin, which is one of the oldest and most prolific producing basins in North America. The Permian Basin, which consists of approximately 75,000 square miles centered around Midland, Texas, has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of formations of oil and natural gas bearing rock throughout.

Non-Permian Divestiture and Significant Acquisitions

Divestiture of Non-Permian Assets

On February 9, 2026, we divested all of our non-Permian assets, including those acquired from Sitio Royalties Corp. (“Sitio”), to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments (the “Non-Permian Divestiture”). The divested properties consisted

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of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d.

Sitio Acquisition

On August 19, 2025, we completed a series of transactions in which New Viper acquired Sitio, Sitio Royalties Operating Partnership, LP (“Sitio OpCo”) and their respective subsidiaries, pursuant to the Agreement and Plan of Merger, dated June 2, 2025, by and among Former Viper, the Operating Company, Sitio, Sitio OpCo, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (the “Sitio Acquisition”). The Sitio Acquisition was an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

2025 Drop Down

On May 1, 2025, we acquired all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC from Endeavor Energy Resources, LP (“Endeavor”), each a seller party and a subsidiary of Diamondback, pursuant to a definitive equity purchase agreement for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of our Class B Common Stock (the “2025 Drop Down”). The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further information.

Our Properties

As of December 31, 2025, our assets consisted of mineral interests and royalty interests underlying approximately 4,462,119 gross royalty acres and 96,003 net royalty acres primarily in the Permian Basin, and Diamondback was the operator of approximately 35% of our net royalty acreage. As of December 31, 2025, there were 43,355 gross productive wells on this acreage, 6,524 of which were operated by Diamondback. Net production during the fourth quarter of 2025 was approximately 134,000 BOE/d and net production for the year ended December 31, 2025, averaged 95,126 BOE/d. For the years ended December 31, 2025, 2024 and 2023, royalty income generated from these mineral and royalty interests was $1.3 billion, $854 million and $717 million, respectively.

At December 31, 2025, our estimated proved oil and natural gas reserves totaled 406,035 MBOE based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. As of December 31, 2025, approximately 78% of our proved reserves were classified as proved developed producing reserves. PUD included in this estimate were from 1,653 gross horizontal well locations. As of December 31, 2025, our proved reserves were approximately 48% oil, 26% natural gas and 26% natural gas liquids.

Our Relationship with Diamondback

As of December 31, 2025, Diamondback beneficially owned 155,058,093 shares of our outstanding Class B Common Stock, representing approximately 42.1% of the then outstanding voting power of our capital stock on a fully diluted basis, after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report). We believe Diamondback’s significant ownership in us may motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so and may elect to hold or dispose of mineral and other interests in such properties without offering us the opportunities to acquire them.

We believe Diamondback views our company as part of its business strategy and that Diamondback may be incentivized to pursue additional acquisitions jointly with us in the future. However, Diamondback will regularly evaluate acquisitions and may elect to acquire properties without offering us the opportunity to participate in such transactions. Moreover, Diamondback may not be successful in identifying potential acquisitions. Diamondback is free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities.

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In addition, neither we nor our Operating Company have any employees. Diamondback provides management, operating and administrative services to us under the services and secondment agreement (the “Services and Secondment Agreement”), including the services of the executive officers and other employees. For additional information, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes in Item 8. Financial Statements and Supplementary Data of this report.

Business Strategies

Our primary business objective is to generate the highest value proposition for our stockholders through a focus on increasing long-term per share growth and returns by generating robust free cash flow, managing our capital structure, including reducing debt, and protecting our balance sheet. We intend to accomplish this objective by executing the following strategies:

•Capitalize on the development of the properties underlying our mineral interests to grow our cash flow. We expect the production from our mineral interests will increase as Diamondback and our other operators continue to develop our acreage by drilling and completing wells. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated increase in our aggregate royalty payment receipts will enable us to grow our cash flows.

•Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We have in the past and intend to continue to make opportunistic acquisitions of mineral and other interests that have substantial oil-weighted resource potential and organic growth potential. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. For example, we and Diamondback may pursue an acquisition where Diamondback acquires working and revenue interests in properties and we acquire mineral, royalty or overriding royalty interests in such properties either in the same or subsequent transactions.

•Seek to acquire from Diamondback or unaffiliated third parties, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral or other interests in producing oil and natural gas properties directly from Diamondback as well as from unaffiliated third parties. We believe Diamondback may continue to be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through dividends on Diamondback’s controlling interests in us. However, neither Diamondback nor any of its affiliates are contractually or otherwise obligated to offer or sell any interests in properties to us. We also may seek to acquire mineral or other interests in producing oil and natural gas properties from unaffiliated third parties, such as our August 2025 acquisition of Sitio.

•High-grade our asset base. We intend to continue to high-grade our asset base and opportunistically divest non-core mineral interests, such as the Non-Permian Divestiture on February 9, 2026, and then redeploy proceeds into our core areas of focus.

•Maintain a conservative capital structure to allow financial flexibility. Since our formation, we have maintained a conservative capital structure that has allowed us to opportunistically purchase accretive mineral and other interests. We are committed to maintaining a conservative leverage profile and will continue to seek to opportunistically fund accretive acquisitions. In addition to returning capital to our stockholders through base and variable dividends in accordance with our dividend policy and share repurchases under our repurchase program, we intend to continue to manage our balance sheet and debt obligations to ensure our ability to successfully operate in challenging business and commodity price environments.

•Hedge to manage commodity price risk and to protect our balance sheet and cash flow. We use a combination of derivative instruments to economically hedge exposure to changes in commodity prices and maintain financial and balance sheet flexibility.

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Competitive Strengths

We believe the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

•Oil rich resource base in one of North America’s leading resource plays. As of December 31, 2025, 244 horizontal drilling rigs were operating in the Permian Basin, representing 46% of the total U.S. onshore horizontal rig activity. The majority of our mineral and royalty acreage is positioned in the core of both the Midland and Delaware Basins in the Permian Basin. Production on our mineral and royalty acreage for the year ended December 31, 2025, and our estimated net proved reserves are heavily oil-weighted.

•Sustainable, high margin business unburdened by capital expenses with minimal operating expenses. Our mineral and royalty interests provide us with cash flows without the requirement to fund drilling and completion costs or lease operating expenses. Our operating margins generate free cash flow growth in a stable or rising price environment as the underlying production associated with our royalty interests continues to grow.

•Experienced and proven management team. Diamondback provides us with personnel and general and administrative services, including the services of the executive officers, senior management and other employees, pursuant to the Services and Secondment Agreement. The members of our executive team have significant industry experience, most of which has been focused on resource play development primarily in the Permian Basin, and Diamondback, which currently operates approximately 35% of our mineral and royalty acreage, has a proven track record of executing on multi-rig development drilling programs and extensive experience primarily in the Permian Basin. In addition, our executive team has significant experience with acquisition of properties and businesses in the oil and natural gas industry. We believe the industry relationships and experience of our management team are essential for the execution of our business strategy.

•Favorable and stable business environment. We primarily focus our growth in the Permian Basin, one of the oldest, most prolific hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks in the Permian Basin as compared to other unconventional hydrocarbon basins. We believe that the impact of the proven application of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities on our mineral and royalty acreage as compared to other unconventional hydrocarbon basins.

•Enhanced Permian Basin footprint facilitating the pursuit of disciplined transactions in highly fragmented minerals market. On August 19, 2025, we completed the Sitio Acquisition, which has significantly expanded our footprint across the core of the Permian Basin and increased our exposure to high quality development activity. We believe that completion and integration of the Sitio Acquisition further enhances our ability to pursue disciplined transactions in what continues to be a highly fragmented minerals market, apply superior land and data capabilities to source and evaluate opportunities and integrate assets efficiently.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

The estimated reserves as of December 31, 2025, 2024 and 2023 are based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. The internal and external technical persons responsible for preparing or auditing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis. The purpose of Ryder Scott’s audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates for 2025, 2024 and 2023. The proved reserve audits performed by Ryder Scott for 2025, 2024 and 2023 covered 100% of our total proved reserves for each respective year. A copy of the summary audit report prepared by Ryder Scott is included as Exhibit 99.1 to this Annual Report.

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Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025, were estimated using a deterministic method.

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (i) performance-based methods, (ii) volumetric-based methods, and (iii) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. In general, our proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods included, but were not limited to, decline curve analysis, which utilized extrapolations of available historical production data. In certain cases where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. All proved undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included, but were not limited to, production data, downhole completion information, geologic data and historical well cost and operating expense data.

The process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates of this report. As a result, our petroleum engineers and geoscience professionals have an internal controls process to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to our assets. Our internal technical staff met with our independent reserve auditors periodically during their audit of the December 31, 2025 reserve report to discuss the assumptions and methods used in our proved reserve estimation process. As part of the audit process, we provide historical information to the independent reserve auditors for our properties such as ownership interest, oil and gas production, commodity prices and operating and development costs. Our Executive Vice President and Chief Engineer is primarily responsible for overseeing the preparation of all of our reserve estimates and overseeing communications with our independent reserve auditor. Our Executive Vice President and Chief Engineer is a petroleum engineer with over 22 years of reservoir and operations experience and our geoscience staff has an average of approximately 17 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, commodity prices and operating and development costs to estimate economic lives of our properties. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2025 and any differences were reviewed with our Executive Vice President and Chief Engineer. For 2025, our reserve auditor’s estimates of our proved reserves did not differ materially from our estimates by more than the established audit tolerance guidelines of ten percent.

The internal control procedures utilized in the preparation of our proved reserve estimates are intended to ensure reliability of reserve estimations, and include, but are not limited to the following:

•review and verification of historical production data, which is based on actual production as reported by our operators;

•preparation of reserve estimates by the primary reserve engineers or under their direct supervision;

•review by the primary reserve engineers of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

•review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;

•direct reporting responsibilities by our Executive Vice President and Chief Engineer to our Chief Executive Officer and by the current primary reserve engineer to our President;

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•prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer, Diamondback’s Executive Vice President and Chief Operating Officer, our Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis;

•review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis;

•verification of property ownership by our land department; and

•no employee’s compensation is tied to the amount of reserves booked.

For estimates and further discussion of our proved developed and proved undeveloped reserves, see Note 15—Supplemental Information on Oil and Natural Gas Operations (Unaudited) in Item 8. Financial Statements and Supplementary Data of this report.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

Our properties are located primarily in the Midland and Delaware Basins of the Permian Basin in Texas. At December 31, 2025, 2024 and 2023, the Midland Basin and the Delaware Basin each contained 15% or more of our total proved reserves.

The following table sets forth information regarding our share of our operators’ net production of oil, natural gas and natural gas liquids for these fields along with our share of our operators’ net production from fields containing less than 15% of our total proved reserves:


	Midland	Delaware	Other(2)	Total
Production Data:
Year Ended December 31, 2025
Oil (MBbls)	14,000	3,579	296	17,875
Natural gas (MMcf)	36,364	13,208	2,104	51,676
Natural gas liquids (MBbls)	5,757	1,243	1,233	8,233
Combined volumes (MBOE)(1)	25,818	7,023	1,880	34,721

Year Ended December 31, 2024
Oil (MBbls)	7,105	2,766	68	9,939
Natural gas (MMcf)	16,802	7,482	322	24,606
Natural gas liquids (MBbls)	2,976	1,174	31	4,181
Combined volumes (MBOE)(1)	12,881	5,187	153	18,221

Year Ended December 31, 2023
Oil (MBbls)	5,789	2,210	29	8,028
Natural gas (MMcf)	13,088	5,984	58	19,130
Natural gas liquids (MBbls)	2,323	782	3	3,108
Combined volumes (MBOE)(1)	10,293	3,989	42	14,324

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)Production data includes the Denver-Julesburg, Eagle Ford and Williston basins beginning August 19, 2025, the effective date on which the properties were acquired.

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The following table sets forth certain average sales price information for each of the periods indicated:


	Year Ended December 31,
	2025		2024		2023
Average Sales Prices:
Oil ($/Bbl)	$	63.27	$	75.48	$	77.13
Natural gas ($/Mcf)	$	1.08	$	0.60	$	1.62
Natural gas liquids ($/Bbl)	$	19.31	$	21.17	$	21.55
Combined ($/BOE)	$	38.77	$	46.85	$	50.06

Oil, hedged ($/Bbl)(1)	$	62.38	$	74.57	$	76.05
Natural gas, hedged ($/Mcf)(1)	$	1.92	$	0.85	$	1.37
Natural gas liquids ($/Bbl)(1)	$	19.31	$	21.17	$	21.55
Combined price, hedged ($/BOE)(1)	$	39.54	$	46.68	$	49.13

(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes realized gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.

Productive Wells

As of December 31, 2025, we owned an average 2.2% net revenue interest in 43,355 gross productive wells, including an average 2.2% net revenue interest in 39,434 gross oil productive wells and an average 1.3% net revenue interest in 3,921 gross natural gas productive wells. As of December 31, 2025, we had 14 gross wells with an average 10.1% net revenue interest in process of being drilled by Diamondback. The expected timing of our wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Productive wells consist of producing wells capable of production, including natural gas awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest.

Acreage

The following table sets forth information as of December 31, 2025, relating to the gross and net royalty acreage of our mineral interests:


Basin	Gross Royalty Acreage	Net Royalty Acreage
Delaware	1,986,216	36,004
Midland	1,891,742	50,595
Other	584,161	9,404
Total acreage	4,462,119	96,003

Our net interest in production from our mineral interests is based on lease royalty terms which vary from property to property. Our interest in the majority of these properties is perpetual in nature; however, a portion of our net royalty acreage consists of overriding royalty interests which may be subject to expiration. Net royalty acres are defined as net mineral acres multiplied by the average lease royalty interest and other burdens.

Title to Properties

Prior to the drilling of an oil or natural gas well, it is typical in our industry for the well operator to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability to increase production and reserves in the future. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, our business and cash available for dividends may be adversely affected.

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Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties, mineral interests and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices than operators of our mineral and royalty acreage. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Our ability to acquire additional mineral, royalty, overriding royalty, net profits and similar interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, fuel oils and nuclear energy. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while demand for natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below. For purposes of this section, where applicable, references to “we,” “us,” and “our” refer to Viper Energy, Inc., to the extent the Company were to acquire working interests in the future as well as to any operators of our properties, including our current operators.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Federal and state legislation and regulation affecting the oil and natural gas industry is evolving. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters. Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas; require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits; result in the suspension or revocation of necessary permits, licenses and authorizations; require that additional pollution controls be installed; and impose substantial liabilities for pollution resulting from operations. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and

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regulations occur frequently, and may result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements that could materially and adversely affect our business and prospects. Further, on January 20, 2025, President Trump issued a series of executive orders and memoranda signaling a shift in environmental and energy policy in the United States, including the revocation of several Biden administration-era executive orders related to public health, the environment, climate change and climate-related financial risks. President Trump also declared a “national energy emergency,” directing agencies to expedite conventional energy projects. While the Trump Administration’s changes to the environmental regulatory landscape in the United States continue to develop, it is possible that additional changes in the future could impact our results of operations and those of our customers.

Waste Handling. The Resource Conservation and Recovery Act, or the RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in the U.S. Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any changes in such laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Additionally, emerging contaminants, like per- and polyfluoroalkyl substances (“PFAS”) such as perfluorooctanesulfonic acid and perfluorooctanoic acid compounds, have become subject to CERCLA regulation in addition to existing federal and state chemicals regulation, and PFAS have recently been regulated under the Toxic Substances Control Act (“TSCA”). Other emerging contaminants could also become subject to regulation under CERCLA, TSCA or comparable state laws. Governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial or regulatory compliance obligations upon our operators would not have a material adverse effect on our operations or financial position.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act of 1990, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.

The scope of waters regulated under the CWA has fluctuated in recent years due to notable rulemaking efforts and judicial challenges. On January 18, 2023, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated

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final rules expanding the scope of waters protected under the CWA. However, on May 25, 2023, the United States Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the decision. Later, on March 12, 2025, the EPA issued guidance narrowing the definition of “wetland” from the Biden-era definition in order to align that definition with the Supreme Court’s May 25, 2023 decision. These recent actions have provided some clarity. However, to the extent the EPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the CWA’s jurisdiction, we or third-party operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. On March 12, 2025, the EPA announced that it is re-evaluating the existing regulations on oil and gas wastewater, including exploring opportunities for discharge from centralized wastewater treatment facilities. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the CWA or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

Air Emissions. The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal CAA that establish new emission controls for oil and natural gas production and processing operations, which are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source if they are under common control for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (including carbon dioxide, methane and other gases). Such rules and regulations have been proposed, amended and challenged, and finalized, and compliance deadlines have been extended or regulations rescinded. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022, or the IRA, include billions of dollars in incentives for the development of renewable energy and supporting infrastructure. In March 2024, the EPA published a final rule in the Federal Register to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. On November 26, 2025, the EPA issued an interim final rule to extend certain compliance deadlines from the March 2024 final rule. These incentives and regulations, if implemented, may encourage the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA amends the CAA to impose a “waste emissions charge” on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their greenhouse gas emissions to the EPA,

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including those sources in offshore and onshore petroleum and natural gas production and gathering and boosting source categories. On November 18, 2024, the EPA published a final rule on the methane emissions charge, which became effective on January 17, 2025. Twenty-three states filed a lawsuit challenging the CAA amendment, and the One Big Beautiful Bill Act, passed July 4, 2025, suspends the “waste emissions charge” from future implementation. The current U.S. presidential administration has also expressed an intention to scale back various other climate regulations launched under previous administrations. On February 12, 2026, the EPA issued a final rule eliminating the 2009 greenhouse gas endangerment finding, which underpins U.S. federal regulation of greenhouses gas emissions under the Clean Air Act. The final rule is expected to be subject to extensive litigation and the impact of such scaling back is difficult to predict at this time. Despite this shift, numerous proposals have been and continue to be made at the international, regional and state levels of government that are intended to limit emissions of greenhouse gases by enforceable requirements and voluntary measures.

The EPA has also finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry. On November 26, 2025, the EPA issued an interim final rule to extend certain compliance deadlines from the March 2024 final rule. Additionally, several states have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and natural gas operations. For example, on November 4, 2020, the Texas Railroad Commission adopted new guidance on when flaring is permissible, requiring operators to submit more specific information to justify the need to flare or vent gas.

In addition to domestic regulation of greenhouse gases, there continues to be international interest in a global framework for greenhouse gas reductions. However, on January 20, 2025, President Trump issued an executive order directing the United States Ambassador to the United Nations to immediately withdraw from the Paris Agreement and revoke the U.S. International Climate Finance Plan, and on January 27, 2025, the United States’ Acting Ambassador to the United Nations submitted a notification of withdrawal from the Paris Agreement. The withdrawal became effective on January 27, 2026.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of the U.S. Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

On March 8, 2024, the EPA published a final rule to expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. On December 1, 2025, the EPA published a final rule extending several compliance deadlines in the March 2024 final rule. This final rule was promptly challenged in federal court by environmental groups. While there is uncertainty regarding the scope and extent of EPA’s regulation of air emissions from hydraulic fracturing operations, any future laws and their implementing regulations may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions. Additionally, in the future, the EPA may impose more stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions, which may increase our compliance or operating costs.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of Federal Occupational Safety and Health Act for

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disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits and temporarily suspend operations for waste disposal wells. For example, in September 2021, the Texas Railroad Commission curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has subsequently suspended some permits there and expanded the restrictions to other areas. In addition, the Texas Railroad Commission has imposed monitoring and reporting requirements for any new disposal well permitted in the Permian Basin. These restrictions on the disposal of produced water, a moratorium on new produced water wells, and additional monitoring and reporting requirements could result in increased operating costs, forcing our operators or their vendors to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. Our operators or their vendors may also limit disposal well volumes, disposal rates and pressures or locations, or require them to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business.

On December 17, 2024, the Texas Railroad Commission adopted a significant overhaul of its rules regulating oil and gas waste management facilities in Texas. The new rules went into effect on July 1, 2025. The new rules, found in 16 TAC Chapter 4, cover waste from oil and gas operations, such as rock and other material pulled up from the ground during drilling, as well as waste from other operations. The rules impose requirements related to waste management practices and production methods, such as recycling produced water. The rules also update requirements on the design, construction, operation, monitoring, and closure of waste management units.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Endangered Species. The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species, such as the lesser prairie chicken or dunes sagebrush lizard, are located in areas where our operators or their vendors operate, their operations or any work performed related to their operations could be prohibited or delayed, or expensive mitigation could be required. The designation of previously unprotected species as threatened or endangered in areas where our operators or their vendors operate could result in the imposition of restrictions on our operators’ or their vendors’ operations or any work related to their operations.

Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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The availability, terms and cost of transportation of oil and natural gas significantly affect its marketability and sale. The interstate transportation and sale for resale of natural gas, and the interstate transportation of oil, is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Oil and natural gas pipelines are also subject to extensive safety regulation by the Pipeline and Hazardous Materials Safety Administration, a part of the U.S. Department of Transportation, and state regulatory agencies. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC regulation of interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas, which is predominantly state-regulated.

Although oil and natural gas prices are currently unregulated, the U.S. Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: the location of wells; the method of drilling and casing wells; the timing of construction or drilling activities, including seasonal wildlife closures; the rates of production or “allowables”; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which they can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure our stockholders that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales. Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Beginning with that legislation in 1978 and continuing with the Wellhead Decontrol Act of 1989, federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties for violations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil (including other liquid hydrocarbons) in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

We do not have any employees. Since the Conversion, our business and affairs are overseen by our board of directors, and Diamondback continues to provide personnel and general and administrative services to us, including the services of the executive officers and other employees, pursuant to the Services and Secondment Agreement. Please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes in Item 8. Financial Statements and Supplementary Data of this report. All of the individuals that conduct our business, including our executive officers, are employed by Diamondback.

Facilities

Our principal executive offices are located in Midland, Texas and are owned by Diamondback. We believe that these facilities are adequate for our current operations.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investors page of our website at www.viperenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.

ITEM 1A. RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of the material risks relating to our business activities. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.

Risks Related to Our Business

Geopolitics and market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth and production.

From the beginning of 2023 through the end of 2025, WTI has ranged from $55.27 to $93.68 per Bbl, and the Henry Hub price of natural gas has ranged from $1.58 to $5.29 per MMBtu. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other

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trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions, and actions taken by OPEC+, continued to contribute to economic and pricing volatility. These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. If the prices of oil and natural gas decline, our operations and financial condition may be materially and adversely affected. Our business may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints in the Permian Basin where we have mineral and royalty interests.

Diamondback and certain of our other operators increased production on our acreage during 2025, but Diamondback continued to exercise capital discipline by using the majority of their excess cash flow for debt repayment and/or return to their stockholders rather than expanding its drilling programs. We cannot reasonably predict whether production levels will remain at current levels or the full extent of the impact of the events above may have on our industry and our business.

Based on the current commodity pricing environment and industry conditions, we recorded non-cash ceiling test impairments of $768 million in 2025. If SEC Prices decline further as compared to commodity prices used in prior periods, we may be required to record additional impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our revolving credit facility, which may be determined at the discretion of our lenders.

Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.

We use commodity price derivatives, which have historically included fixed price swap contracts, fixed price basis swap contracts and costless collar contracts with corresponding put and call options to reduce price volatility associated with certain of our royalty income. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on WTI pricing (WTI Cushing and Argus WTI Midland) and with natural gas derivative settlements based on the Henry Hub and Waha Hub pricing. By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. Our counterparties have been determined to have an acceptable credit risk; therefore, we do not require collateral from our counterparties. By using derivative instruments, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas and natural gas liquids above the price levels of the commodity price derivatives used to manage price risk.

For additional information regarding our use of commodity price derivatives and our outstanding derivative contracts as of December 31, 2025, see Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

The risks relating to the transition to a low carbon economy could impose new costs on our operations that may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have evolving and varied views on climate change matters in recent years. Such views, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in: (i) the enactment of new or evolving climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in battery technology), (iii) variability in demand from consumers and industry for energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles), and (iv) development of, and variable demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, oil and natural gas, which would likely have a material adverse impact on our

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investments. The enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see Items 1 and 2. Business and Properties—Regulation—Climate Change of this report.

In addition to potentially reducing demand for oil and natural gas, and the availability of oilfield services and midstream and downstream customers, further regulatory or other climate change initiatives, to the extent they continue, may create investment and reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. Certain stakeholders and capital providers may seek to restrict or seek to impose more stringent conditions with respect to their investment in or financing of certain carbon intensive sectors, which could result in capital being unavailable to us, or only at a significantly increased cost.

Changing political and social perspectives on climate change and other environmental, social and governance factors may create risks and uncertainties impacting our business.

We may not be able to meet evolving expectations of stakeholders, including governmental officials, standard setters, investors, employees, and customers, relating to climate change, human capital, and other environmental, social and governance (“ESG”) issues. There is conflicting and evolving pressures from proponents and opponents of ESG, and a failure to adapt to changing views could negatively impact our reputation. Proponents and opponents of these issues are increasingly resorting to activism, including litigation, to advance their positions. Such activism also includes attempts to effect changes to public companies’ businesses or governance to deal with climate change-related issues through shareholder proposals, public campaigns, proxy solicitations or other actions. Any such future actions may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, whether due to our activities or the activities of the acquired entities or operations prior to their acquisition by us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages. Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions to our business, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and cash flow.

Increased costs of capital could adversely affect our business.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

We may not have sufficient available cash to pay any quarterly dividend on our Common Stock, our cash available for dividends may vary significantly from quarter to quarter and our board of directors may in the future modify or revoke our cash dividend policy at any time at its discretion. Our dividend policy could limit our ability to grow and make acquisitions.

We may not have sufficient cash available to pay base or variable dividends to our common stockholders each quarter. Furthermore, our cash dividend policy does not require us to pay dividends on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends upon the amount of royalty income we generate, which is dependent upon the volumes of production sold and the prices that our operators realize from the sale of such production. In addition, the actual amount of cash we will have to distribute each quarter under our cash dividend policy will be reduced by payments in respect of income taxes, debt service and other contractual obligations and fixed charges, increases in reserves for future operating or capital needs that the board of directors may determine is appropriate, lease bonus income, dividend equivalent rights payments and preferred dividends, if any, and any common share repurchases. The board of directors may further modify or revoke our dividend policy at any time in the future at its discretion. For information regarding our dividend policy and the recent modifications, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report. As a result, quarterly dividends paid to our stockholders may vary significantly from quarter to quarter and may be zero.

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As a result of our cash dividend policy, we have limited cash available to reinvest in our business or to fund acquisitions. We expect that we will continue to fund a portion of our capital expenditures and other needs with borrowings under the revolving credit facility and from the proceeds of debt and equity offerings. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could result in an inability to complete acquisitions or finance the capital expenditures necessary to replace our reserves.

To the extent we issue additional shares in connection with any acquisitions or growth capital expenditures or as in-kind dividends, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level.

We depend on a small number of operators for a substantial portion of the development and production on our mineral and royalty acreage. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of an operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Any development and production activities on our properties are subject to our operators’ reasonable discretion. The level, success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including: commodity prices; the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated; the ability of our operators to access capital; the availability, high cost or shortages of rigs and other suitable drilling equipment, raw materials, supplies and oilfield services; the availability of production and transportation infrastructure and qualified operating personnel; regulatory restrictions; the operators’ expertise, operating efficiency and financial resources; approval of other participants in drilling wells; the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; the selection of technology; the selection of counterparties for the sale of production; and the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty income and cash available for dividends to our stockholders. If reductions in production by the operators are implemented on our properties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures by operators than we currently anticipate.

Approximately 22% of our total estimated proved reserves as of December 31, 2025, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators on our mineral and royalty acreage. The reserve data included in our reserve reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill, complete and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

We may not be able to terminate our leases if any of our operators declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

Under many of the leases that cover our mineral and royalty interests, a failure on the part of our operators to make royalty payments to us gives us the right to terminate the applicable lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

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However, many of our mineral and royalty interests are covered by leases that do not provide us with the contractual right to terminate the lease or repossess the property if an operator fails to timely make royalty payments to us. In such instances, we may be forced to resort to litigation to seek payment of past due royalties and statutory interest, without the ability to replace the operator.

The producing properties in which we have mineral and royalty interests are primarily concentrated in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with a single geographic area. In addition, a large amount of our proved reserves is attributable to a small number of producing horizons within this area.

The producing properties in which we have mineral and royalty interests are currently geographically primarily concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints faced by our operators or their customers, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids on our mineral and royalty acreage, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities on our mineral and royalty acreage.

Extreme regional weather events may occur that can affect our operators’ suppliers or customers, which could adversely affect us. Climate changes may also increase the frequency and severity of significant weather events over time. Further, any increase in flaring of natural gas production on our mineral and royalty acreage due to weather-related events, or otherwise, could expose us to reputational risks and adversely impact our or our operators’ contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us. Likewise, a weather event could reduce the availability of electrical power, road accessibility, and transportation facilities, which could have an adverse impact on production volumes on our mineral and royalty acreage (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our mineral and royalty acreage, we could experience any of these conditions at the same time, resulting in a relatively greater impact on us than they might have on other companies that have a more diversified portfolio of assets. Such delays or interruptions could have a material adverse effect on our business, financial condition and cash flow.

In addition to the geographic concentration of our mineral and royalty acreage, as of December 31, 2025, most of our proved reserves are concentrated in the Wolfberry resource play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause our operators to permanently or temporarily shut-in all of the wells on our mineral and royalty acreage.

Our future success depends on the development or acquisition of additional reserves, and our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for dividends.

Our future success depends upon the development or acquisition of additional oil and natural gas reserves that are economically recoverable, as our proved reserves will generally decline as reserves are depleted. To increase reserves and production, we would need to undertake replacement activities or use our operators to undertake development, exploration and other replacement activities, requiring substantial capital expenditures. We may not have sufficient resources to acquire additional reserves and our operators may not have sufficient resources to undertake exploration, development, production or other replacement activities. Such activities by our operators may not result in significant additional reserves and efforts to drill productive wells at low finding costs may be unsuccessful. In addition, we do not expect to retain cash from our operations for replacement capital expenditures. Furthermore, although our revenues and cash available for dividends may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including: recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems including title defects or environmental issues, which, if material, can render an interest worthless, nor will it permit us to become sufficiently familiar with the properties to assess fully their

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deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Environmental or other regulatory issues may arise with respect to acquired entities or operations years after the acquisitions, any of which can adversely affect our results of operations, financial condition and cash available for dividends. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Significant acquisitions and other strategic transactions may involve other risks that may cause our business to be adversely impacted, including diversion of our management’s attention to evaluating and negotiating such transactions and our failure to realize the full benefit that we expect in estimated proved reserves, production volume or other benefits anticipated therefrom, or to realize these benefits within the expected time frame.

We may not be able to complete acquisitions or do so on commercially acceptable terms, as our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, our future acquisitions may be in geographic regions in which we do not currently hold properties. If we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements and other unforeseen difficulties. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations, the process of which may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. Any of the unfavorable circumstances mentioned above could have a material adverse effect on our financial condition, results of operations and cash available for dividends. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for dividends.

We may not realize the anticipated benefits from our acquisitions, including the Sitio Acquisition and the 2025 Drop Down.

We have recently completed several significant acquisitions, including the Sitio Acquisition and the 2025 Drop Down, and expect to pursue additional acquisitions as part of our growth strategy. Realizing anticipated benefits from these acquisitions depends in part on integrating acquired assets efficiently and effectively, which we may not accomplish due to, among other things:

•challenges associated with operating a larger organization and managing geographically dispersed assets;

•the difficulty of integrating corporate, technological and administrative functions and complex systems, technology and networks, and addressing inconsistencies in standards, controls, operational philosophies and corporate cultures;

•diversion of attention and resources from regular business operations;

•increasing our indebtedness and the complexity of our capital structure;

•incurring environmental or regulatory liabilities and encountering title defects;

•disruptions in relationships with operators, customers, suppliers, landowners and other business partners;

•challenges in hiring, training, retaining or integrating qualified personnel;

•assuming unknown or contingent liabilities and incurring unforeseen expenses; and

•inaccuracies in assumptions regarding estimated proved reserves, future production, prices, revenues and costs.

If we are unable to effectively manage the integration of our current or future acquisitions, or if our business activities are interrupted as a result, our business, results of operations and financial condition could be adversely affected.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed are on our property and do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for dividends may be materially affected.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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recoveries and operating and development costs, if any. As a result, estimated quantities of proved reserves and projections of future production rates may be incorrect. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices and production levels may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A portion of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

We are dependent on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.

We are dependent on electric power, internet and telecommunication infrastructure and Diamondback’s information systems and computer based programs. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively conduct our business will be limited and any such consequence could have a material adverse effect on our business.

Rapid growth in artificial intelligence (“AI”) related data centers and other high‑intensity computing is materially increasing regional electricity demand and straining grids, which—together with extreme weather conditions, intermittent renewable generation, and other market constraints—can reduce power availability, increase prices (including scarcity pricing), and cause outages. Reduced power reliability could disrupt our operators’ drilling, completion, and production activities; impair midstream operations; hinder remote monitoring and data integrity; and force suspensions or shutdowns or unplanned spending on backup power and communications, any of which could have a material adverse effect on our business and results of operations.

We are subject to cybersecurity and data privacy risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

We rely extensively on Diamondback’s information technology systems and infrastructure, including but not limited to data hosting platforms, real-time data acquisition systems, internally developed and third-party software, cloud services and other internally or externally hosted hardware and software platforms (collectively, “IT Systems”) for operational and other purposes, such as to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, and (iii) communicate with our management and board of directors, as well as, our vendors, suppliers and other third parties. Diamondback owns and manages certain IT Systems but also relies on third parties for a range of IT Systems and other products or services. Diamondback and certain third-party providers also collect, maintain and/or process proprietary data about our business, such as trade secrets, as well as personally identifiable information about our employees, business partners and others (collectively, “Confidential Information”).

We regularly experience attempted cyberattacks and other incidents, including phishing attacks and attacks on certain of our third-party providers, and we expect future cyberattacks and incidents to occur in varying degrees. To date, no incidents have materially affected our company, including our business strategy, results of operations or financial condition, but we cannot guarantee that material incidents will not occur in the future.

Diamondback’s IT Systems and our Confidential Information, and those of our vendors, service providers and other third-party providers and business partners, are vulnerable to evolving cybersecurity threats, including, without limitation, denial-of-service attacks; malicious software (e.g., ransomware); the exploitation of known and unknown misconfigurations, “bugs,” and other hardware or software vulnerabilities; data privacy breaches by insiders or others with authorized access; social engineering (e.g., phishing) attacks; attempts to gain unauthorized access to our data and Diamondback’s systems; and other electronic or physical security breaches. More recently, advancements in AI pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition or screening questions to confirm identities. In addition, generative AI systems are increasingly used by malicious actors to create more sophisticated cyber-attacks (i.e., more realistic phishing or other attacks) and to circumvent controls, evade detection and even remove forensic evidence, rendering incident detection and remediation more challenging. These and other threat-related advancements expose us and Diamondback to increasing costs, including costs associated with additional personnel, protection technologies and policies and procedures and third-party experts and consultants. There can be no assurance that Diamondback’s cybersecurity risk management program, including its controls or processes, will be fully implemented,

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complied with or effective in protecting IT Systems and Confidential Information. Moreover, neither we nor Diamondback manage the security controls or processes deployed by our third-party providers, such as cloud services that support our operations, and therefore, successful cyberattacks that disrupt or result in unauthorized access to third-party IT Systems could materially impact our and Diamondback’s operations and financial results. Similarly, we have acquired and continue to acquire companies that may have cybersecurity vulnerabilities or unsophisticated measures, which exposes us to significant risk. A significant cybersecurity attack or incident could compromise our Confidential Information or disrupt our operations, normal business functions and other aspects of our business.

Diamondback provides personnel and general and administrative services to us, including personnel and infrastructure that underlie our cybersecurity risk management program. As cyber incidents continue to evolve, Diamondback may be required to expend additional resources (for which we may be partially responsible) to continue to modify or enhance protective measures or to investigate and remediate any vulnerability to cyber incidents. Diamondback maintains specialized insurance for possible liability resulting from a cyberattack on its assets; however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that Diamondback will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and cash flows. See Item 1C. Cybersecurity below for additional information.

A variety of U.S. federal, state and international laws and regulations govern the collection, use, retention, sharing and security of personal data. All 50 states have enacted legislation on data breach notification requirements and many states continue to enact laws on matters of privacy, data protection and cybersecurity. The existing privacy-related laws and regulations are evolving and subject to potentially differing interpretations. In addition, various U.S. federal, state and foreign legislative and regulatory bodies continue to enact new laws regarding privacy and data protection, as well as expand the scope of existing laws. We cannot predict the impact of any such evolving privacy-related laws on our business, results of operations or financial condition, but may find it necessary to enhance the existing systems and procedures, which may involve substantial expense or distraction from other aspects of our business. In addition, any violations of applicable privacy-related laws or regulations may require us to address legal claims, sustain monetary penalties or incur other liabilities, as well as cause reputational damage, any of which could adversely impact our business, results of operations or financial condition.

Risks Related to Our Indebtedness

Our substantial indebtedness could adversely affect our results of operations, business flexibility and our ability to service our debt.

We have incurred a substantial amount of debt to finance our recent acquisitions and for other corporate purposes. Our ability to make scheduled payments of principal, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. We are dependent on cash flow generated by the Operating Company to repay the Guaranteed Senior Notes. The Operating Company’s business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If the Operating Company is unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional capital on terms that may be onerous or highly dilutive. However, we cannot assure you that alternative financing plans would be consummated on desirable terms or would be adequate to meet any debt service obligations then due.

Our revolving credit facility and the indentures governing the Guaranteed Senior Notes outstanding contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create additional liens; sell or transfer assets; merge or consolidate with another entity; pay or declare dividends; designate certain of our subsidiaries as unrestricted subsidiaries; create unrestricted subsidiaries; and engage in transactions with affiliates.

In addition, the revolving credit facility requires us to maintain a certain net debt to capitalization ratio. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these restrictive covenants could result in default under the revolving credit facility. If a default occurs, the lenders under the revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which

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would result in an event of default under the indentures governing the Guaranteed Senior Notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under the revolving credit facility and the Guaranteed Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Additionally, any significant reduction in the borrowing base under our revolving credit facility as a result of borrowing base redeterminations, following a decline in commodity prices or otherwise, may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operations and cash flow. Further, if the outstanding borrowings under the revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of the borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Lastly, our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate tied to SOFR. SOFR tends to fluctuate based on multiple factors, including general short-term interest rates, rates set by the U.S. Federal Reserve, and other central banks and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Risks Inherent in an Investment in Us

Diamondback controls us and its interests may conflict with ours or yours in the future.

Diamondback beneficially owns approximately 42.1% of the voting power of our capital stock, on a fully diluted basis. For so long as Diamondback continues to have voting power over a significant percentage of our capital stock, even at times when such amount is less than 50%, it will be able to significantly influence the composition of our board of directors and the approval of actions requiring stockholder approval. Although the holders of our Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the General Corporation Law of the State of Delaware (the “DGCL”), including the election of our board of directors, pursuant to our certificate of incorporation, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of our outstanding Common Stock (i) Diamondback has the right to designate up to three persons to serve as members of our board of directors, and (ii) our board of directors may not appoint any person other than a Diamondback seconded employee as an executive officer of our company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned), or (y) the affirmative vote of the holders of at least 80% of the voting power of our capital stock. Currently, there are two Diamondback designees to our board of directors—Travis Stice and Kaes Van’t Hof. Pursuant to the Services and Secondment Agreement, Diamondback continues to provide personnel and general and administrative services to us and OpCo, including the services of the executive officers and other employees. Accordingly, Diamondback will have significant influence with respect to our board of directors, management, business plans and policies, including the appointment and removal of our officers. In particular, for so long as Diamondback continues to beneficially own a significant percentage of our capital stock, it will be able to cause or prevent a change of control of our company or a change in the composition of our board of directors and could preclude any unsolicited acquisition of our company. The concentration of ownership could deprive you of an opportunity to receive a premium for your shares of Common Stock as part of a sale of our company and ultimately might affect the market price of our Common Stock.

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We do not have any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and certain of its affiliates, and thus are not solely focused on our business.

We do not have any employees and we rely solely on Diamondback to provide us with personnel and general and administrative services, including the services of the executive officers, senior management and other employees, under the terms and conditions of the Services and Secondment Agreement. Because Diamondback provides services to us that are similar to those it performs for itself and its affiliates, it may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it were solely focused on our business and operations. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself or others in providing its services. If Diamondback does not devote sufficient attention to the management and operation of our business or otherwise breaches the provisions of the services and secondment agreement, our financial results may suffer and our ability to pay dividends to our stockholders may be reduced. Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of the executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

The market price of our shares of Class A Common Stock could be adversely affected by sales of substantial amounts of our Class A Common Stock in the public or private markets.

We have provided registration rights to Diamondback and other parties collectively owning a substantial portion of our outstanding shares of Class A Common Stock on an as-converted basis. Pursuant to these registration rights, we have registered, under the Securities Act, all of the Class A Common Stock owned by Diamondback and those other parties for resale (including Class A Common Stock issuable in respect of the Class B Common Stock under the related exchange agreement or under the exchange provisions of the Operating Company’s limited liability company agreement). Sales by holders of a substantial number of our Class A Common Stock in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A Common Stock or could impair our ability to obtain capital through an offering of equity securities.

U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

In 2022, the IRA enacted a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting more than $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. If we are or become subject to CAMT including as a result of our affiliation with Diamondback, our cash tax obligations for U.S. federal income taxes could be significantly accelerated.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law. Among other provisions, the OBBB provides for immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the CAMT, and enhancements to limits on business interest expense deductions. The OBBB also imposes limits on deductibility of charitable contributions by corporations. To the extent the timing or amount of our tax deductions are affected by the applicable provisions of the OBBB, our cash tax obligations may be impacted.

The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue additional guidance on how the CAMT and other provisions of the IRA and OBBB will be applied or otherwise administered,

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and such guidance may differ from our interpretations. We continue to evaluate the IRA and OBBB and their effect on our financial results and operating cash flow.

The provision of our certificate of incorporation requiring exclusive venue in the Court of Chancery in the State of Delaware for certain types of lawsuits may have the effect of discouraging lawsuits against us and our directors, officers and stockholders.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware generally shall be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or stockholder of the Company to the Company or its stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or bylaws or (iv) any other action asserting a claim against the Company governed by the internal affairs doctrine. This choice of forum provision does not waive our compliance with our obligations under the federal securities laws and the rules and regulations thereunder. Moreover, the provision does not apply to suits brought to enforce a duty or liability created by the Exchange Act or by the Securities Act.

This choice of forum provision may increase costs to bring a claim, discourage claims or limit a stockholder’s ability to bring a claim in a judicial forum that the stockholder finds favorable for disputes with the Company or our directors, officers or employees, which may discourage such lawsuits against the Company and its directors, officers and employees, even though an action, if successful, might benefit our stockholders. Alternatively, if a court were to find the choice of forum provision to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such matters in other jurisdictions, which could increase our costs of litigation and adversely affect our business and financial condition.

Our certificate of incorporation does not limit the ability of Diamondback and certain of its directors, principals, officers, employees and their respective affiliates to compete with us.

Our certificate of incorporation provides that none of Diamondback, any of its directors, principals, officers, employees or respective affiliates will have any duty to refrain from engaging, directly or indirectly, in the same business activities or similar business activities or lines of business in which we operate. In the ordinary course of their business activities, these persons may engage in activities where their interests conflict with our interests or those of our other stockholders.

These persons also may pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, these persons may have an interest in our pursuing acquisitions, divestitures and other transactions that, in their judgment, could enhance their investment, even though such transactions might involve risks to our common stockholders.

Anti-takeover provisions in our organizational documents and Delaware law might discourage or delay acquisition attempts for us that you might consider favorable.

Our certificate of incorporation and bylaws contain provisions that may make the merger or acquisition of our company more difficult without the approval of our board of directors. Among other things, these provisions would allow us to authorize the issuance of shares of one or more series of preferred stock, including in connection with a stockholder rights plan, financing transactions or otherwise, the terms of which series may be established and the shares of which may be issued without stockholder approval, and which may include super voting, special approval, dividend, or other rights or preferences superior to the rights of the holders of Common Stock; prohibit stockholder action by written consent unless such action is consented to by the board of directors; provide for certain limitations on convening special stockholder meetings; provide (i) that the board of directors is expressly authorized to make, alter, or repeal our bylaws, and (ii) that our stockholders may only amend our bylaws with the approval of at least a majority of all of the outstanding shares of our capital stock entitled to vote; and establish advance notice requirements for nominations for elections to our board or for proposing matters that can be acted upon by stockholders at stockholder meetings.

These anti-takeover provisions could discourage, delay or prevent a transaction involving a change in control of our company, including actions that our stockholders may deem advantageous, or could negatively affect the trading price of our Common Stock. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

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Our ability to pay base and variable dividends to the holders of our Class A Common Stock or make repurchases under our repurchase program may be limited by requirements under our certificate of incorporation, our holding company structure, applicable provisions of Delaware law and contractual restrictions.

Under our current dividend policy, we pay quarterly base plus variable cash dividends on our Class A Common Stock. The outstanding shares of Class B Common Stock are entitled to an aggregate quarterly preferred dividend of $20,000 in cash. Other than the insignificant preferred dividend requirement, we are not required to pay dividends to our stockholders on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of our board of directors, which may change our dividend policy at any time. Our ability to pay cash dividends to holders of our Class A Common Stock depends on a number of factors, including among other things, general economic and business conditions, our strategic plans and prospects, our businesses and investment opportunities, our financial condition and operating results, capital requirements and other anticipated cash needs, contractual restrictions and obligations, legal, tax and regulatory restrictions and other factors.

Additionally, as a holding company, our ability to pay dividends or repurchase shares of our Common Stock or OpCo Units is subject to the ability of OpCo and any future subsidiaries to provide cash to us. Viper Energy, Inc. has no material assets other than its membership interest in OpCo, which along with OpCo’s subsidiaries, holds all of the mineral and royalty interests and other assets consolidated on our balance sheet.

Under the DGCL we may only pay dividends to our stockholders out of (i) our surplus, as defined and computed under the provisions of the DGCL, or (ii) our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. If we do not have sufficient surplus or net profits, we will be prohibited by law from paying any such dividend. In addition, the terms of our revolving credit facility include, and any other debt instruments or financing arrangements may from time to time include covenants or other restrictions that could constrain our ability to pay dividends, make other distributions or repurchase shares of our Common Stock or OpCo Units. Our certificate of incorporation contains provisions authorizing us to issue series of preferred stock that may have designations, preferences, rights, powers and duties that are different from, and may be senior to, those applicable to our Class A Common Stock.

For additional information regarding stockholders’ equity and our repurchase program, see Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity Risk Management Strategy

Diamondback provides us with personnel and general and administrative services pursuant to the Services and Secondment Agreement, including the personnel and infrastructure that underlie our cybersecurity risk management program. In connection therewith, Diamondback has implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect Diamondback’s systems, identify and remediate on a regular basis vulnerabilities in Diamondback’s systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. Diamondback has also engaged third-party consultants to conduct penetration testing and risk assessments. Diamondback’s cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.

Diamondback’s cybersecurity risk management program is integrated into its overall enterprise risk management program, which integrates our enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas that apply to us.

Diamondback’s cybersecurity risk management program, which it provides to us under the Services and Secondment Agreement, includes:

•risk assessments designed to help identify material cybersecurity risks to critical systems, information, products, services, and the broader enterprise IT and operational technology (“OT”) environments;

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•a security team principally responsible for managing (i) cybersecurity risk assessment processes, (ii) security controls, and (iii) its response to cybersecurity incidents;

•the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of its security controls;

•security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity;

•cybersecurity awareness training of its employees, including incident response personnel and senior management, including those who provide these services for us;

•cybersecurity tabletop exercises for members of its cybersecurity incident response team and legal department;

•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and

•a third-party risk management process for service providers, which may include diligence, assessments and/or contractual requirements, depending on each service provider’s operational criticality and relative risk profile.

Cybersecurity Governance

Diamondback’s cybersecurity governance program is led by its Senior Vice President and Chief Information Officer, with support from the internal information technology department. Diamondback’s Senior Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. Diamondback’s Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, Diamondback’s cybersecurity incident response team is responsible for responding to cybersecurity incidents and is guided by its Computer Security Incident Response Plan. Progress and developments in Diamondback’s cybersecurity governance program are communicated to members of its and our executive team. Diamondback’s and our management takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by Diamondback; alerts and reports produced by security tools deployed in the enterprise IT and OT environments; and through reporting by employees and service providers. While our board of directors is ultimately responsible for enterprise-wide risk oversight, the board’s committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. In particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in the risk management strategy and continues to be an area of increasing focus for our board, the audit committee and management.

The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program. Board members also receive presentations on cybersecurity topics from Diamondback’s Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Diamondback’s cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors.

Risks from identified cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A. Risk Factors of this report for additional information regarding cybersecurity risks we face and their potentially material impact on our business strategy, results of operations and financial condition.

ITEM 3. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencie s in Item 8. Financial Statements and Supplementary Data of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Listing and Holders of Record

Shares of our Class A Common Stock are listed on Nasdaq under the symbol “VNOM.” There were 63 holders of record of our Class A Common Stock on February 20, 2026. There is no trading market for our Class B Common Stock; however, shares of our Class B Common Stock or the TWR Class B Option (as defined in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), together with an equal number of OpCo Units, are exchangeable for the same number of shares of our Class A Common Stock at the discretion of the holders under the terms and conditions of OpCo’s limited liability company agreement or the applicable exchange agreement with such holders. There were 31 holders of record of our Class B Common Stock on February 20, 2026.

Dividend Policy

Under our current dividend policy, we intend to pay a base dividend, as well as a variable dividend that takes into account capital returned to stockholders via our repurchase program. We currently intend to pay quarterly variable dividends of at least 75% of our available cash less the base dividend declared and the amount paid for repurchases of our Common Stock and OpCo Units as part of our repurchase program for the applicable quarter.

Our available cash and the available cash of the Operating Company for each quarter is determined by our board of directors following the end of such quarter. We expect that our available cash will generally equal the Adjusted EBITDA attributable to us for the applicable quarter, less cash needed for income taxes payable, debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that our board of directors deems necessary or appropriate, lease bonus income (net of applicable taxes), and other insignificant expenses including dividend equivalent rights payments and preferred distributions.

The percentage of cash available for distribution by the Operating Company to us pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen our balance sheet while also expanding the return of capital program through our repurchase program.

We are also required to pay a quarterly preferred dividend in respect of our Class B Common Stock in the aggregate amount of $20,000 per quarter. Other than the preferred dividend requirement, we are not required to pay dividends to our stockholders on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of our board of directors.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

Our Class A Common Stock repurchase activity for the three months ended December 31, 2025, was as follows:


Period	Total Number of Shares Purchased(1)	Average Price Paid Per Share(2)		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(1)(3)
	(In millions, except per share amounts and shares in ones)
October 1, 2025 - October 31, 2025	861,825	$	37.34	860,087	$	302
November 1, 2025 - November 30, 2025	466,757	$	36.97	466,757	$	284
December 1, 2025 - December 31, 2025	75,905	$	38.72	75,905	$	241
Total	1,404,487	$	37.29	1,402,749

(1)Includes 1,738 shares of Class A Common Stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase. On December 10, 2025 our board of directors approved expanding the repurchase program to include repurchases of OpCo Units and shares of Class B

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Common Stock. The OpCo Units and the Company’s Class B Common Stock are not registered securities pursuant to Section 12 of the Exchange Act and as such repurchases of such unregistered securities are excluded from the shares listed in the table above. During December 2025, the Company, in a privately negotiated transaction, repurchased 1,000,000 OpCo Units for an aggregate purchase price of approximately $41 million, or $40.65 per OpCo Unit, and cancellation of an equal number of shares of the Company’s Class B Common Stock. The approximately $241 million remaining under the repurchase program for future repurchases at December 31, 2025 in the table above gives effect to such repurchase of OpCo Units.

(2)The average price paid per share includes any commissions paid to repurchase stock.

(3)On July 26, 2022, our board of directors increased the authorization under our then-in-effect repurchase program from $250 million to $750 million and on February 18, 2026 further increased the authorization to $1.75 billion. This repurchase program has no expiration date and remains subject to market conditions, applicable legal requirements, contractual obligations and other factors and may be suspended, modified or extended, from time to time, or may be discontinued at any time, in each case, by our board of directors.

Stock Performance Graph

The following performance graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate such information by reference into such a filing. The performance graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.

The performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP. The graph assumes an investment of $100 on December 31, 2020, and that all dividends were reinvested.


	As of December 31,
Calculated Values	2020	2021	2022	2023	2024	2025
Viper Energy, Inc.	$100.00	$194.07	$314.02	$328.99	$544.01	$454.07
S&P 500	$100.00	$128.68	$105.36	$133.03	$166.28	$195.98
XOP	$100.00	$166.76	$242.36	$250.96	$248.37	$243.04

ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in Item 8. Financial Statements and Supplementary Data of this report. 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 discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this report.

Overview

The following discussion includes a comparison of our results of operations, including changes in our operating income, and liquidity and capital resources for fiscal year 2025 and fiscal year 2024. A discussion of changes in our results of operations from fiscal year 2024 compared to fiscal year 2023 has been omitted from this report, but may be found in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 26, 2025, and is incorporated by reference in this report from such prior Annual Report on Form 10-K.

Recent Developments

2026 Activity

Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under our existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax.

Cash Dividends

On February 18, 2026, our board of directors approved (i) an increase to our annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025, and (ii) a combined quarterly base and variable cash dividend of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit payable on March 12, 2026.

Divestiture of Non-Permian Assets

On February 9, 2026, we completed the Non-Permian Divestiture for net cash proceeds of approximately $617 million, subject to 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 current production of approximately 4,750 BO/d. Proceeds from the Non-Permian Divestiture were used to repay the Term Loan (as defined below) and to reduce borrowings outstanding on the 2025 Revolving Credit Facility (as defined below).

2025 Activity

Acquisitions Update

Sitio Acquisition

On August 19, 2025, we completed the Sitio Acquisition in an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

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2025 Drop Down

On May 1, 2025, we completed the 2025 Drop Down for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of our Class B Common Stock (collectively, the “Drop Down Equity Issuance”). The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback.

Other Acquisitions

During the year ended December 31, 2025, we acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $140 million, including customary closing adjustments. Additionally, during the year ended December 31, 2025, we acquired from Morita Ranches Minerals, LLC, mineral and royalty interests representing 1,691 net royalty acres in the Permian Basin for consideration consisting of $208 million in cash and 2,400,297 OpCo Units together with an equal number of shares of our Class B Common Stock, including customary transaction costs and post-closing adjustments.

At December 31, 2025, our footprint of mineral and royalty interests totaled approximately 96,003 net royalty acres, approximately 35% of which are operated by Diamondback.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further information.

Debt Transactions

Notes Offering and Retirement of Notes

On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion. Using approximately $824 million of the net proceeds from the issuance of the Guaranteed Senior Notes, we redeemed all of our 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”) and on November 1, 2025 we redeemed our 5.375% Senior Notes due 2027 (the “2027 Notes”), including accrued and unpaid interest through the date of redemption and any redemption premiums. We used the remaining net proceeds to partially retire Sitio’s net debt of approximately $1.2 billion including any fees, costs and expenses related to the redemption or repayment of such debt, and for general corporate purposes.

Additionally, in the second quarter of 2025, prior to redemption, we opportunistically repurchased principal amounts of $50 million of the 2027 Notes in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which is now the issuer with respect to the Guaranteed Senior Notes.

Term Loan

On July 23, 2025, Former Viper, as guarantor, the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, entered into a $500 million term loan credit agreement (the “Term Loan”), which was fully drawn to partially fund the retirement of Sitio’s net debt. Following the closing of the Sitio Acquisition, New Viper became an additional guarantor of the borrower’s obligations under the Term Loan. Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent providing for a senior unsecured revolving credit facility with a commitment amount of $1.5 billion (the “2025 Revolving Credit Facility”). The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the Operating Company, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced

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the borrower’s previous revolving credit facility, and will mature on June 12, 2030, unless extended in accordance with its terms. Following the OpCo Conversion, Viper LP became the borrower under the 2025 Revolving Credit Facility.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt.

2025 Equity Offering

On February 3, 2025, we completed an underwritten public offering of 28,336,000 shares of our Class A Common Stock, which included 3,696,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $44.50 per share, for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to fund (i) a portion of the cash consideration for the 2025 Drop Down, (ii) the cash consideration for various individually insignificant acquisitions, and (iii) for general corporate purposes.

Commodity Prices and Certain Other Market Considerations

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions and other substantially variable factors influence market conditions for these products. 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 2025, 2024 and 2023, WTI prices averaged $64.73, $75.76 and $77.60 per Bbl, respectively, and Henry Hub prices averaged $3.62, $2.41 and $2.66 per MMBtu, respectively. For additional information around risks related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Based on 2025 commodity prices, industry conditions and the results of the quarterly ceiling tests, we were required to record aggregate non-cash impairments of $768 million on our proved oil and natural gas interests during the year ended December 31, 2025. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.

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Production and Operational Update

As of December 31, 2025, there were 98 gross rigs operating on our mineral and royalty acreage, eight of which are operated by Diamondback. During 2025, we completed the Sitio Acquisition and the 2025 Drop Down, which reinforced the durability of our growth outlook and leveraged our leading position in the minerals and royalty sector to advance our differentiated acquisition strategy. Currently, we estimate full year production levels in 2026 to range between approximately 120 MBOE/d to 132 MBOE/d.

The following table summarizes our gross well information excluding the recently divested non-Permian assets as of December 31, 2025, unless otherwise specified:


	Diamondback Operated		Third-Party Operated		Total
Horizontal wells turned to production (fourth quarter 2025)(1):
Gross wells	107		632		739
Net 100% royalty interest wells	5.3		7.7		13.0
Average percent net royalty interest	5.0	%	1.2	%	1.8	%

Horizontal wells turned to production (year ended December 31, 2025)(2):
Gross wells	415		1,670		2,085
Net 100% royalty interest wells	20.7		21.3		42.0
Average percent net royalty interest	5.0	%	1.3	%	2.0	%

Horizontal producing well count:
Gross wells	4,092		19,942		24,034
Net 100% royalty interest wells	258.3		311.1		569.4
Average percent net royalty interest	6.3	%	1.6	%	2.4	%

Horizontal active development well count(3):
Gross wells	263		1,125		1,388
Net 100% royalty interest wells	20.9		17.3		38.2
Average percent net royalty interest	7.9	%	1.5	%	2.8	%

Line of sight wells(4):
Gross wells	304		1,066		1,370
Net 100% royalty interest wells	16.9		15.1		32.0
Average percent net royalty interest	5.6	%	1.4	%	2.3	%

(1)Average lateral length of 11,283 feet.

(2)Average lateral length of 11,618 feet.

(3)The total 1,388 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.

(4)The total 1,370 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 net royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Results of Operations

The following table summarizes our income and expenses for the periods indicated:


	Year Ended December 31,
	2025		2024
	(In millions)
Operating income:
Oil income	$	1,131	$	750
Natural gas income	56		15
Natural gas liquids income	159		89
Royalty income	1,346		854
Lease bonus income	24		6
Lease bonus income—related party	24		—
Other operating income	1		1
Total operating income	1,395		861
Costs and expenses:
Production and ad valorem taxes	94		61

Depletion	607		214
Impairment	768		—
General and administrative expenses	18		8
General and administrative expenses—related party	17		11

Other operating expenses	31		—
Total costs and expenses	1,535		294
Income (loss) from operations	(140)		567
Other income (expense):
Interest expense, net	(96)		(74)

Gain (loss) on derivative instruments, net	44		11

Gain (loss) on early extinguishment of debt	(32)		—
Other income (expense), net	(1)		—
Total other income (expense), net	(85)		(63)
Income (loss) before income taxes	(225)		504
Provision for (benefit from) income taxes	(19)		(100)
Net income (loss)	(206)		604
Net income (loss) attributable to non-controlling interest	(138)		245
Net income (loss) attributable to Viper Energy, Inc.	$	(68)	$	359

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:


	Year Ended December 31,
	2025		2024
Production data:
Oil (MBbls)	17,875		9,939
Natural gas (MMcf)	51,676		24,606
Natural gas liquids (MBbls)	8,233		4,181
Combined volumes (MBOE)(1)	34,721		18,221

Average daily oil volumes (BO/d)	48,973		27,156
Average daily combined volumes (BOE/d)	95,126		49,784


Average sales prices:
Oil ($/Bbl)	$	63.27	$	75.48
Natural gas ($/Mcf)	$	1.08	$	0.60
Natural gas liquids ($/Bbl)	$	19.31	$	21.17
Combined ($/BOE)(2)	$	38.77	$	46.85

Oil, hedged ($/Bbl)(3)	$	62.38	$	74.57
Natural gas, hedged ($/Mcf)(3)	$	1.92	$	0.85
Natural gas liquids ($/Bbl)(3)	$	19.31	$	21.17
Combined price, hedged ($/BOE)(3)	$	39.54	$	46.68

Average costs ($/BOE):
Production and ad valorem taxes	$	2.71	$	3.34

General and administrative - cash component	0.81		0.86
Total operating expense - cash	$	3.52	$	4.20

General and administrative - non-cash stock compensation expense	$	0.20	$	0.16
Interest expense, net	$	2.76	$	4.05
Depletion	$	17.48	$	11.77

(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 2025 compared to the same period in 2024 are discussed 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 $492 million in 2025 compared to the same period in 2024. This net increase consisted of an additional $701 million in royalty income from the 91% growth in production, partially offset by a net decrease of $209 million due primarily to lower average prices received for our oil and natural gas liquids production during 2025 compared to the same period in 2024.

Of the 91% growth in production, approximately 46% is attributable to the 2025 Drop Down and 32% is attributable to the Sitio Acquisition. The remainder of the growth is primarily from new wells added between periods and other individually insignificant acquisitions. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our acquisitions.

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Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated:


	Year Ended December 31,
	2025						2024
	Amount (In millions)		Per BOE		Percentage of Royalty Income		Amount (In millions)		Per BOE		Percentage of Royalty Income
Production taxes	$	69	$	1.99	5.1	%	$	43	$	2.33	5.0	%
Ad valorem taxes	25		0.72		1.9		18		1.01		2.1
Total production and ad valorem taxes	$	94	$	2.71	7.0	%	$	61	$	3.34	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. Production taxes and ad valorem taxes as a percentage of royalty income in 2025 were relatively consistent with the same period in 2024.

Depletion. The increase in depletion expense of $393 million in 2025 compared to the same period in 2024 consisted primarily of (i) $198 million due to an increase in the depletion rate to $17.48 per BOE in 2025, resulting primarily from the addition of leasehold costs and reserves from acquisitions completed in 2025, compared to $11.77 per BOE for the same period in 2024, and (ii) $195 million from growth in production volumes.

Impairment. In 2025, we recorded non-cash ceiling test impairment charges of $768 million due to the carrying value of our proved reserves exceeding their estimated future net cash flows utilizing the SEC’s methodology and pricing at December 31, 2025. The excess value resulted primarily from recording properties acquired in the 2025 Drop Down at Diamondback’s historical carrying value, which exceeded the value calculated in the third and fourth quarter 2025 ceiling tests, due primarily to declining SEC Prices. No impairment expense was recorded in 2024.

Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Given the overall decline in SEC Prices from the first quarter of 2025 through the first two months of 2026, we believe an additional material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026; however, based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026.

General and Administrative Expenses. The following table shows a breakout of our general and administrative expenses for the periods presented:


	Year Ended December 31,
	2025		2024
	(In millions, except per BOE amounts in ones)
General and administrative expenses	$	18	$	8
General and administrative expenses—related party	17		11
General and administrative expenses	$	35	$	19

General and administrative expenses (per BOE)	$	1.01	$	1.02

Interest Expense, Net. The increase in net interest expense of $22 million in 2025 compared to the same period in 2024 consisted primarily of (i) $40 million in additional expense on our Guaranteed Senior Notes, which were issued July 23, 2025, (ii) $11 million in additional interest expense incurred on the Term Loan, and (iii) other individually insignificant changes. These increases in net interest expense were partially offset by (i) interest cost savings of approximately $16 million due to the early termination of the Notes, (ii) $8 million in additional interest income, and (iii) a decrease of approximately $5

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million in interest expense on our current and previous revolving credit facility due to lower average borrowings outstanding in 2025.

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:


	Year Ended December 31,
	2025		2024
	(In millions)
Gain (loss) on derivative instruments, net	$	44	$	11
Net cash receipts (payments) on derivatives	$	30	$	(3)

The $33 million increase in the gain on derivative instruments, net in 2025 compared to the same period in 2024 consists primarily of (i) an $11 million net gain on our natural gas contracts, which consists of a $30 million net increase in cash receipts on our settled natural gas basis swaps, partially offset by a $19 million decrease in the value of our open natural gas contracts primarily due to changes in the differential between prices for Waha Hub and Henry Hub, (ii) a $13 million decrease in the estimated fair value of our 2026 WTI Contingent Liability based on fluctuations in the final WTI 2025 Average price (each as defined in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), and (iii) other individually insignificant changes. See Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our open contracts at December 31, 2025.

Gain (Loss) on Early Extinguishment of Debt. The $32 million loss on early extinguishment of debt in 2025 is due to the retirement of the 2031 Notes. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt at December 31, 2025.

Provision for (Benefit from) Income Taxes. The $81 million decrease in income tax benefit in 2025 compared to the same period in 2024 primarily resulted from recognizing a pre-tax loss attributable to Viper in 2025 compared to pre-tax income attributable to Viper in 2024, driven by the $768 million non-cash ceiling test impairments recorded in 2025. Additionally, the income tax benefit recognized in 2024 reflects the full release of a valuation allowance of $156 million during the fourth quarter of 2024. See Note 9—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of income tax expense.

Net Income (Loss) Attributable to Non-Controlling Interest. The change to $138 million in net loss attributable to non-controlling interest in 2025 from $245 million in net income attributable to non-controlling interest in 2024 is primarily due to the non-cash ceiling test impairments recorded in 2025 and changes in the non-controlling interest in the Operating Company resulting from (i) the Drop Down Equity Issuance, (ii) the issuance of OpCo Units to fund the Sitio Acquisition, and (iii) the issuance of OpCo Units to Tumbleweed Royalty IV, LLC in the fourth quarter of 2024, which were partially offset by a dilution of the non-controlling interest following the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report) and the 2025 Equity 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. Our primary sources of liquidity have been cash flow from operations, equity and debt offerings, borrowings under our revolving credit facility, term loan agreement 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, including the recently completed Sitio Acquisition, the 2025 Drop Down, and various individually insignificant acquisitions and repurchases of our Common Stock and OpCo Units. At December 31, 2025, we had approximately $1.4 billion of liquidity consisting of $13 million in cash and cash equivalents and $1.4 billion in available borrowings under the 2025 Revolving Credit Facility. See further discussion of changes in our sources of cash in “—Capital Resources” below.

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Our working capital requirements are supported by our cash and cash equivalents and the 2025 Revolving Credit Facility. We may draw on the 2025 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.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

Continued prolonged volatility in the capital, financial and/or credit markets due to changing or adverse macroeconomic conditions, including tariffs, higher interest rates, global supply chain disruptions, actions taken by OPEC members and other exporting nations and geopolitical global conflicts may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

Cash Flows

The following table presents our cash flows for the period indicated:


	Year Ended December 31,
	2025		2024
	(In millions)
Net cash provided by (used in) operating activities	$	1,053	$	620
Net cash provided by (used in) investing activities	(2,424)		(608)
Net cash provided by (used in) financing activities	1,357		(11)
Net increase (decrease) in cash and cash equivalents	$	(14)	$	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 and natural gas sold by our operators. The increase in net cash provided by operating activities in 2025, compared to the same period in 2024 was primarily driven by an increase in royalty and lease bonus income and receiving cash payments on our derivatives in 2025 compared to making cash payments to counterparties in 2024. These increases in cash flow were partially offset by an increase in certain cash costs for production and ad valorem taxes, general and administrative expenses, other operating expenses which include severance costs related to the Sitio Acquisition and other changes in our working capital accounts including the timing of when accounts receivable are collected and accounts payable are remitted. See “—Results of Operations” above for further discussion of significant changes in our income and expenses.

Investing Activities

Net cash used in investing activities during the year ended December 31, 2025, was primarily related to acquisitions of oil and natural gas interests, including the approximately $1.2 billion repayment made for Sitio’s outstanding debt as part of the consideration for the Sitio Acquisition, the 2025 Drop Down, and acquisitions of oil and natural gas interests from other third parties. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for additional information on these acquisitions.

Net cash used in investing activities during the year ended December 31, 2024, primarily related to acquisitions of oil and natural gas interests from third parties, which includes $654 million in cash paid for the Tumbleweed Acquisitions (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), partially offset by proceeds of $88 million primarily from the divestiture of non-Permian oil and natural gas interests.

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Financing Activities

Net cash provided by financing activities during the year ended December 31, 2025, was primarily attributable to (i) net proceeds from the issuance of the Guaranteed Senior Notes of $1.6 billion, (ii) proceeds of $1.2 billion from the 2025 Equity Offering, and (iii) net proceeds from the Term Loan of $500 million. These cash inflows were partially offset by (i) $745 million of dividends paid to holders of our OpCo Units and our Class A Common Stock, (ii) $430 million paid for the retirement of the outstanding principal on our 2027 Notes, (iii) $427 million paid for the retirement of the outstanding principal and the redemption premium on our 2031 Notes, (iv) $194 million of securities repurchases under the Company’s repurchase program, and (v) repayments net of borrowings of $156 million on the 2025 Revolving Credit Facility.

Net cash used in financing activities during the year ended December 31, 2024, was primarily attributable to $481 million of dividends paid to stockholders and the Operating Company’s unitholders, which was largely offset by proceeds of $476 million from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report).

Capital Resources

The 2025 Revolving Credit Facility and Other Debt Instruments

At December 31, 2025, our credit facility, which matures on June 12, 2030, had a commitment amount of $1.5 billion, with $105 million in outstanding borrowings and $1.4 billion of availability. In the first quarter of 2026, we fully repaid the $105 million of outstanding borrowings under our credit facility.

Additionally, at December 31, 2025, we had $500 million in outstanding borrowings under the Term Loan, which we subsequently repaid in full with proceeds from the Non-Permian Divestiture in February 2026.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our outstanding debt at December 31, 2025.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S., which impact the interest rates we receive on our variable rate debt and interest rate swaps. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. In May 2025, Fitch Investor Services upgraded our credit rating to investment grade, the second such investment grade credit rating for us. This upgrade granted us access to a broader investor base, lower interest rates and reduced collateral requirements; therefore, enhancing our liquidity. Currently, our credit ratings from the three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB-);

•Fitch Investor Services (BBB-); and

•Moody’s Investor Services (Ba1).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

Guaranteed Senior Notes

At December 31, 2025, we had total principal payments due on our outstanding Guaranteed Senior Notes of $500 million in 2030 and $1.1 billion in 2035. Additionally, we have a remaining aggregate interest expense obligation of $750 million on the Guaranteed Senior Notes with $87 million due in 2026, an aggregate of $174 million due for years 2027 to 2028, an aggregate of $174 million due for years 2029 to 2030, and $315 million due thereafter. The Guaranteed Senior Notes are not subject to any mandatory redemption or sinking fund requirements. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for further information on the Notes.

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Repurchases of Securities

On December 10, 2025, our board of directors expanded our 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 IRA. Since the inception of our repurchase program through February 20, 2026, we have repurchased an aggregate of 18,878,469 shares of our Common Stock and OpCo Units for a total cost of $525 million, excluding any applicable excise tax, leaving approximately $1.2 billion for future repurchases under the repurchase program. See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program.

Cash Dividends and Return of Capital Update

We paid a total of $745 million and $481 million in dividends, on our Class A Common Stock, OpCo Units and participating securities under the LTIP during 2025 and 2024, respectively.

Because of our high operating and free cash flow margin, strong balance sheet, and the Non-Permian Divestiture closure, we returned 90% of cash available for distribution to stockholders with respect to the fourth quarter of 2025. As a result, in addition to repurchases under our repurchase program, we will pay a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case payable on March 12, 2026, to eligible holders of record at the close of business on March 5, 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 $0.14 per share of Class A Common Stock.

We moved closer to our net debt target of $1.5 billion following the closure of the Non-Permian Divestiture on February 9, 2026, and are positioned to increase our return of capital upwards of 100% of future cash available for distribution to stockholders, while also delivering sustainable per-share growth.

See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program and dividends. We expect to continue paying quarterly cash dividends in respect of our common shares. Future base and variable dividends are not required and are at the discretion of the board of directors, who may change the dividend policies at any time.

Supplemental Guarantor Disclosure

On July 9, 2025, New Viper, Former Viper and the Operating Company filed a registration statement on Form S-3 with the SEC registering debt securities of the Operating Company. On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion, which are fully and unconditionally guaranteed by each of Former Viper and New Viper. Following the OpCo Conversion, Viper LP became the issuer of the Guaranteed Senior Notes.

The Guaranteed Senior Notes and the guarantees are the issuer’s and each guarantor’s respective senior unsecured obligations and rank equally in right of payment with all of the issuer’s and each guarantor’s respective existing and future senior indebtedness, including all of the issuer’s and each guarantor’s obligations under the 2025 Revolving Credit Facility and the New Loan, and senior in right of payment to any of the issuer’s and each guarantor’s future indebtedness that is expressly subordinated in right of payment to the Guaranteed Senior Notes and the guarantees, respectively.

The Guaranteed Senior Notes and the guarantees are effectively subordinated to any of the issuer’s and each guarantor’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and are structurally subordinated to all of the existing and future indebtedness and other liabilities (including trade payables) of each of the issuer’s and each guarantor’s respective subsidiaries that is not an obligor on 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 of the issuer or such guarantor 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.

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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 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 consolidated financial statements and management believes such summarized financial information would be repetitive and would not provide incremental value to investors.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our 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 we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Any effects on our 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Royalty Income and Revenue Recognition

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales from third-party operators other than Diamondback may not be received for 30 to 90 days after the date production is delivered. 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 based upon our royalty interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the operator. We have existing internal controls for our royalty income estimation process and related accruals, but actual third-party royalty income in future periods could differ materially from estimated amounts. At December 31, 2025, our accrual for third-party royalty income was approximately $95 million. Actual revenues received during 2025 for prior years’ production from third parties were not materially different than the amount accrued at December 31, 2024.

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Oil and Natural Gas Accounting and Reserves

We account for oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.

Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future depletion of capitalized costs and result in impairment of assets that may be material. Aggregate non-cash ceiling test impairments of $768 million were recorded on our proved oil and natural gas properties during the year ended December 31, 2025. No impairments were recorded on our proved oil and natural gas properties during the years ended December 31, 2024 and 2023. Based on SEC Prices for oil and natural gas throughout 2025 and into 2026, we believe an additional impairment is reasonably likely to occur in the first quarter of 2026. Any future impairment could be material to our consolidated financial statements.

Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) at least annually for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: (i) monitoring information available from third-party operators of our acreage for future drilling plans, (ii) the success of operators drilling on our acreage, (iii) the assignment of proved reserves, and (iv) current market prices for mineral acreage within our primary basins. At December 31, 2025, our unevaluated properties totaled $4.9 billion. We did not record any impairment on our unevaluated properties during the year ended December 31, 2025, but any such future impairment could be material to our consolidated financial statements.

Acquisitions of Mineral and Royalty Interests

Acquisitions of mineral and royalty interests from third parties are accounted for as asset acquisitions, whereby the purchase price and associated transaction costs are typically capitalized and allocated to the acquired mineral and royalty interests. The allocation is determined based on whether the interests acquired relate to proved or unproved oil and natural gas properties, utilizing the estimated fair value of proved reserves as of the date of acquisition. The valuation of proved reserves for acquisitions from unrelated parties is based on a projection of future cash flows using objective future pricing assumptions and a discount rate consistent with our estimated cost of capital at the time of the acquisition.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We use 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 after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to us. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. Estimating future taxable income requires numerous judgments and

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assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas liquids, the expected timing and quantity of future production volumes, and the impact of our commodity derivative instruments on our income. These assumptions are discussed further in the critical accounting estimates titled “— Royalty Income and Revenue Recognition” and “— Oil and Natural Gas Accounting and Reserves.” Due to the impact these various assumptions and estimates can have on our estimates of taxable income, an estimate of the sensitivity to changes is not practicable.

In 2025, management’s assessment of all available evidence, both positive and negative, supporting realizability of our deferred tax assets as required by applicable accounting standards, supported the conclusion that our deferred tax assets are more likely than not to be realized. A variety of positive evidence was assessed. In recent years, we have sustained cumulative pre-tax income due in part to higher commodity prices resulting from strong and stable market conditions, and the locations in which we operate have experienced a sustained and increasing pattern of development by a wide variety of operators, consistent with a presumption of more readily predictable development patterns for our properties. The significant acquisitions completed by us, including the Sitio Acquisition and the 2025 Drop Down, provide additional production capacity to generate future taxable income for utilization of our deferred tax assets. In addition, the recently closed Non-Permian Divestiture provides positive evidence supporting realizability of our capital loss carryforward against the estimated capital gain to be recognized in 2026. Based on these factors, we determined that no valuation allowance on our deferred tax assets is required as of December 31, 2025. As of December 31, 2025, we had net deferred tax assets of $33 million.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for discussion of recent accounting pronouncements and a full listing of our significant accounting policies.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized prices are driven primarily by the prevailing worldwide price for crude oil and prices for natural gas in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable and the prices that our operators receive for production depend on many factors outside of our or their control, as discussed in Item 1A. Risk Factors of this report. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We historically have used fixed price swap contracts, fixed price basis swap contracts, deferred premium put contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data of this report.

At December 31, 2025, we had a net asset derivative position related to our commodity price derivative contracts of $21 million. Utilizing actual derivative contractual volumes under our contracts as of December 31, 2025, a 10% increase in forward curves associated with the underlying commodity would have increased the net asset position by $5 million to approximately $26 million, and a 10% decrease in forward curves associated with the underlying commodity would have

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increased the net asset position by $2 million to approximately $23 million. However, any cash derivative gain or loss may be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas properties and receivables with a limited number of several significant operators who sell our production to numerous purchasers. For the years ended December 31, 2025 and 2024, two operators each accounted for more than 10% of our income, respectively. For the year ended December 31, 2023, one operator accounted for more than 10% of our income. See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for further details. Each of our operators sell to multiple purchasers. We do not require collateral and the failure or inability of our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Volatility in the commodity pricing environment and macroeconomic conditions may enhance the credit risk from our operators and purchasers.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the 2025 Revolving Credit Facility and the Term Loan.

The terms of the 2025 Revolving Credit Facility provide for interest on borrowings at a floating rate equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case, plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate loans and from 1.125% to 2.000% per annum in the case of term SOFR loans, in each case, based on the pricing level. Further, the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitment, based on the pricing level. The pricing level depends on the rating of our long-term senior unsecured debt by certain rating agencies. As of December 31, 2025, we had $105 million in outstanding borrowings under the 2025 Revolving Credit Facility with a weighted average interest rate of 6.02% during the year ended December 31, 2025.

Borrowings under the Term Loan bear interest at a per annum rate elected by us that is equal to SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies. In addition, the fee on undrawn commitments is equal to 0.20% per annum on the aggregate principal amount of such commitments. As of December 31, 2025, we had $500 million in outstanding borrowings under the Term Loan with a weighted average interest rate on borrowings of 5.72% for the year ended December 31, 2025.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


(a)	Documents included in this report:
	1. Financial Statements
	Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	45
	Consolidated Statements of Operations	48
	Consolidated Balance Sheets	49
	Consolidated Statements of Cash Flows	50
	Consolidated Statement of Stockholders’ Equity	51
	Notes to Consolidated Financial Statements	53
	1. Organization and Basis of Presentation	53
	2. Summary of Significant Accounting Policies	55
	3. Revenue from Contracts with Customers	60
	4. Acquisitions and Divestitures	61
	5. Oil and Natural Gas Interests	65
	6. Debt	66
	7. Stockholders’ Equity	68
	8. Earnings Per Common Share	71
	9. Income Taxes	72
	10. Derivatives	74
	11. Fair Value Measurements	75
	12. Commitments and Contingencies	77
	13. Subsequent Events	77
	14. Segment Information	78
	15. Supplemental Information on Oil and Natural Gas Operations (Unaudited)	78

	2. Financial Statement Schedules
	Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Viper Energy, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Viper Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of operations, cash flows, and stockholders’ equity for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 25, 2026 expressed an unqualified opinion.

Basis for opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of proved reserves as it relates to the calculation and recognition of depletion and impairment expense and the valuation of acquired reserves in connection with the mineral and royalty interests acquired in the Sitio Acquisition

As described further in Note 2 to the consolidated financial statements, the Company accounts for its oil and natural gas properties using the full cost method of accounting, which requires management to make estimates of proved reserve volumes and future revenues to calculate depletion and impairment expense. Additionally, as described further in Note 4 to the consolidated financial statements, the Company acquired significant mineral and royalty interests through the Sitio Acquisition which requires management to make estimates of reserve volumes and future revenues to value the properties. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the timing and volumetric amounts of production and corresponding decline rate of producing properties associated with the operator’s development plan. In addition, the estimation of reserves is impacted by management’s judgments and estimates regarding the financial performance of wells to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions. For acquired reserves, management utilizes an estimated fair value pricing model in determining the corresponding value of reserves. We identified the estimation of reserves attributable to oil and natural gas interests, including acquired reserves in the Sitio Acquisition, due to its impact on depletion and impairment expense and acquisition accounting, as a critical audit matter.

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The principal considerations for our determination that the estimation of proved reserves is a critical audit matter are that changes in certain inputs and assumptions, which include a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves, could have a significant impact on the measurement of depletion and impairment expense and the fair value of acquired proved oil and natural gas interests. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of reserves included the following, among others.

•We tested the design and operating effectiveness of key controls relating to management’s estimation of proved reserves for the purpose of calculating depletion and impairment expense and management’s estimation of the fair value of the acquired oil and natural gas interests in the Sitio Acquisition.

•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and independent petroleum engineering specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s reserve volumes, and read the year-end reserve report audited by the independent petroleum engineering specialists.

•Identified inputs and assumptions that were significant to the period end determination of proved reserve volumes and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Compared the pricing used in the reserve report to relevant pricing benchmarks and realized prices related to revenue transactions recorded in the current year;

◦Vouched, on a sample basis, the net revenue interests used in the reserve report to underlying land and division order records;

◦Assessed forecasted production estimates by (i) comparing prior year forecasted production amounts to current year actual results and (ii) comparing forecasted production amounts in the current year reserve report to the actual historical production amounts in the current year, in total and for a sample of individual wells;

◦We obtained the Company's assessment of operators’ development plans for proved undeveloped properties reflected in the reserve report and evaluated it against the Company’s historical conversion rates to evaluate the likelihood of development related to the proved undeveloped properties; and

◦Applied analytical procedures on inputs to the reserve report by comparing to historical actual results and to the prior year reserve report.

•Identified inputs and assumptions that were significant to the estimated fair value of the acquired oil and natural gas interests in the Sitio Acquisition and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Evaluated the appropriateness of fair value pricing, including pricing differentials, used in the fair value reserve report by comparing the pricing forecast to observable pricing information as of the acquisition closing date and pricing differentials to actual historical realized pricing of the acquired properties;

◦Evaluated the level of knowledge, skill and ability of the specialist utilized by the Company to assist in the preparation of the estimates of fair value of oil and natural gas properties acquired;

◦Utilized a valuation specialist to evaluate the reasonableness of the Company’s valuation methodology of the Sitio Acquisition, including testing key inputs and assumptions by understanding and assessing the process used to develop the estimate or through development of an independent expectation;

◦Evaluated the appropriateness of the discount rate used in the fair value reserve report of proved reserves by comparing to the Company’s actual weighted average cost of capital;

◦Compared, on a sample basis, the net revenue interest used in the fair value reserve report to the historical reserve report;

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◦Assessed forecasted production estimates in the fair value reserve report for reasonableness by comparing forecasted production amounts to the actual historical production amounts and to the forecasted production in the year-end reserve report for a sample of individual wells;

◦Applied analytical procedures on the fair value reserve report’s forecasted production by comparing to the prior year reserve report’s forecasted production and to the year-end reserve report’s forecasted production of the acquired proved properties; and

◦Compared the unproved acreage value allocated to other recent acquisitions in the same or similar locations.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2013.

Oklahoma City, Oklahoma

February 25, 2026

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Viper Energy, Inc.

Consolidated Statements of Operations


	Year Ended December 31,
	2025		2024		2023
	(In millions, except per share amounts, shares in thousands)
Operating income:
Oil income	$	1,131	$	750	$	619
Natural gas income	56		15		31
Natural gas liquids income	159		89		67
Royalty income	1,346		854		717
Lease bonus income	24		6		2
Lease bonus income—related party	24		—		108
Other operating income	1		1		1
Total operating income	1,395		861		828
Costs and expenses:
Production and ad valorem taxes	94		61		50

Depletion	607		214		146
Impairment	768		—		—
General and administrative expenses	18		8		7
General and administrative expenses—related party	17		11		4

Other operating expenses	31		—		1
Total costs and expenses	1,535		294		208
Income (loss) from operations	(140)		567		620
Other income (expense):
Interest expense, net	(96)		(74)		(47)

Gain (loss) on derivative instruments, net	44		11		(26)

Gain (loss) on early extinguishment of debt	(32)		—		—
Other income (expense), net	(1)		—		—
Total other income (expense), net	(85)		(63)		(73)
Income (loss) before income taxes	(225)		504		547
Provision for (benefit from) income taxes	(19)		(100)		46
Net income (loss)	(206)		604		501
Net income (loss) attributable to non-controlling interest	(138)		245		301
Net income (loss) attributable to Viper Energy, Inc.	$	(68)	$	359	$	200

Net income (loss) attributable to common shares:
Basic	$	(0.48)	$	3.82	$	2.69
Diluted	$	(0.48)	$	3.82	$	2.69
Weighted average number of common shares outstanding:
Basic	142,530		93,932		74,176
Diluted	142,530		93,932		74,176

See accompanying notes to consolidated financial statements.

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Viper Energy, Inc.

Consolidated Balance Sheets


	December 31,
	2025		2024
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	13	$	27

Royalty income receivable (net of allowance for credit losses)	262		149
Royalty income receivable—related party	88		31


Prepaid expenses and other current assets	50		31
Total current assets	413		238
Property:
Oil and natural gas properties:
Proved properties	9,746		3,533
Unproved properties	4,910		2,180
Other property, equipment and land	8		6
Accumulated depletion and impairment	(2,455)		(1,081)
Property, net	12,209		4,638

Deferred income taxes (net of allowances)	33		185

Other assets	16		8
Total assets	$	12,671	$	5,069
Liabilities and Stockholders’ Equity
Current liabilities:



Accrued liabilities	$	107	$	43


Other current liabilities	4		6
Total current liabilities	111		49
Long-term debt, net	2,186		1,083



Other long-term liabilities	11		30
Total liabilities	2,308		1,162
Commitments and contingencies (Note 12)
Stockholders’ equity:
Class A Common Stock, $0.000001 par value: 1,000,000,000 shares authorized; 170,942,687 and 102,977,142 shares issued and outstanding as of December 31, 2025, and December 31, 2024, respectively	—		—
Class B Common Stock, $0.000001 par value: 1,000,000,000 shares authorized; 187,023,698 and 85,431,453 shares issued and outstanding as of December 31, 2025, and December 31, 2024, respectively	—		—
Additional paid-in capital	4,726		1,569
Retained earnings (accumulated deficit)	(278)		118
Total Viper Energy, Inc. stockholders’ equity	4,448		1,687
Non-controlling interest	5,915		2,220
Total equity	10,363		3,907
Total liabilities and stockholders’ equity	$	12,671	$	5,069

See accompanying notes to consolidated financial statements.

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Viper Energy, Inc.

Consolidated Statements of Cash Flows


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	(206)	$	604	$	501
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	(83)		(149)		(7)
Depletion	607		214		146
Impairment	768		—		—
(Gain) loss on derivative instruments, net	(44)		(11)		26
Net cash receipts (payments) on derivatives	30		(3)		(13)
(Gain) loss on extinguishment of debt	32		—		—



Other	13		6		3
Changes in operating assets and liabilities:

Royalty income receivable	(25)		(13)		(27)
Royalty income receivable—related party	(34)		(28)		3
Accounts payable and accrued liabilities	(19)		7		6
Accounts payable—related party	(2)		1		1



Other	16		(8)		(1)
Net cash provided by (used in) operating activities	1,053		620		638
Cash flows from investing activities:

Acquisitions of oil and natural gas interests	(1,549)		(696)		(830)
Acquisitions of oil and natural gas interests—related party	(875)		—		(75)


Proceeds from sale of oil and natural gas interests	—		88		(3)


Net cash provided by (used in) investing activities	(2,424)		(608)		(908)
Cash flows from financing activities:







Proceeds from debt	3,250		842		973
Repayments of debt	(2,163)		(844)		(462)

Net proceeds from public offering	1,232		476		—




Proceeds from public offering to Diamondback	—		—		200

Repurchases of shares of Class A Common Stock as part of the repurchase program	(153)		—		(95)
Repurchases of OpCo Units as part of the repurchase program	(41)		—		—
Dividends to stockholders	(328)		(219)		(129)
Dividends to Diamondback	(361)		(255)		(196)
Dividends to other non-controlling interest	(56)		(7)		—
Other	(23)		(4)		(13)
Net cash provided by (used in) financing activities	1,357		(11)		278
Net increase (decrease) in cash and cash equivalents	(14)		1		8
Cash and cash equivalents at beginning of period	27		26		18
Cash and cash equivalents at end of period	$	13	$	27	$	26

Supplemental disclosure of cash flow information:
Interest paid	$	(70)	$	(74)	$	(40)
Cash paid for income taxes, net of refunds:
Federal	$	(47)	$	(53)	$	(50)
State	$	(2)	$	(3)	$	(1)
Supplemental disclosure of non—cash transactions:
Class A Common Stock issued for acquisition	$	(1,435)	$	—	$	(255)
OpCo Units issued for acquisitions	$	(1,445)	$	(468)	$	—
OpCo Units issued to related party	$	(3,599)	$	—	$	—

See accompanying notes to consolidated financial statements.

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Viper Energy, Inc.

Consolidated Statements of Stockholders’ Equity


							General				Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Non-Controlling Interest
	Limited Partners						Partner		Common Stock(1)
	Common Units	Amount		Class B Units	Amount		Amount		Class A Shares	Class B Shares
																	Total

Balance at December 31, 2022	73,230	$	689	90,710	$	1	$	1	—	—	$	—	$	—	$	1,631	$	2,322
Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock	(78,126)	(937)		(90,710)	(1)		—		78,126	90,710	938		—		—		—
Liquidation of General Partner	—	—		—	—		(1)		—	—	(1)		—		—		(2)
Common shares/units issued for acquisition	—	—		—	—		—		9,018	—	255		—		—		255
Common shares/units issued to related party	7,215	200		—	—		—		—	—	—		—		—		200
Equity-based compensation	—	1		—	—		—		—	—	—		—		—		1
Vesting of restricted stock shares/units	73	—		—	—		—		—	—	—		—		—		—

Dividends/distributions to shareholders	—	(84)		—	—		—		—	—	—		(45)		—		(129)
Dividends/distributions to Diamondback	—	(1)		—	—		—		—	—	—		(4)		(191)		(196)

Change in ownership of consolidated subsidiaries, net	—	31		—	—		—		—	—	(133)		—		102		—
Repurchases as part of share/unit buyback	(2,392)	(67)		—	—		—		(1,000)	—	(28)		—		—		(95)
Net income (loss)	—	168		—	—		—		—	—	—		32		301		501
Balance at December 31, 2023	—	$	—	—	$	—	$	—	86,144	90,710	$	1,031	$	(17)	$	1,843	$	2,857

(1)The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero at December 31, 2023.

See accompanying notes to consolidated financial statements.

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Viper Energy, Inc.

Consolidated Statements of Stockholders’ Equity - (Continued)


	Common Stock(1)
			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Non-Controlling Interest
	Class A Shares	Class B Shares
									Total
	(In millions, shares in thousands)


















Balance at December 31, 2023	86,144	90,710	$	1,031	$	(17)	$	1,843	$	2,857

Common shares issued for acquisition	5,279	(5,279)	—		—		—		—
OpCo Units issued for acquisition	—	—	—		—		468		468
Common shares issued to related party	11,500	—	476		—		—		476
Equity-based compensation	—	—	3		—		—		3
Issuance of shares upon vesting of equity awards	54	—	—		—		—		—




Dividends to stockholders	—	—	—		(219)		—		(219)
Dividends to Diamondback	—	—	—		(5)		(250)		(255)
Dividends to other non-controlling interest	—	—	—		—		(7)		(7)
Change in ownership of consolidated subsidiaries, net	—	—	59		—		(79)		(20)


Net income (loss)	—	—	—		359		245		604
Balance at December 31, 2024	102,977	85,431	1,569		118		2,220		3,907

Common shares issued for acquisitions	38,536	38,020	1,435		—		—		1,435
Common shares issued to related party	—	69,627	—		—		—		—
OpCo Units issued for acquisition	—	—	—		—		1,445		1,445

OpCo Units issued to related party	—	—	—		—		3,599		3,599
Net proceeds from the issuance of Common Stock	28,336	—	1,232		—		—		1,232
Repurchases of shares of Class A Common Stock under repurchase program	(4,016)	—	(153)		—		—		(153)
Repurchases of OpCo Units and cancellation of Class B Common Stock under repurchase program	—	(1,000)	—		—		(41)		(41)
Conversion of Class B Common Stock to Class A Common Stock	5,054	(5,054)	188		—		(188)		—
Dividends to stockholders	—	—	—		(327)		—		(327)
Dividends to Diamondback	—	—	—		—		(361)		(361)
Dividends to other non-controlling interest	—	—	—		—		(56)		(56)
Dividend equivalent rights payments	—	—	—		(1)		—		(1)
Equity-based compensation	—	—	7		—		—		7
Issuance of shares upon vesting of equity awards	56	—	—		—		—		—

Change in ownership of consolidated subsidiaries, net	—	—	448		—		(565)		(117)
Net income (loss)	—	—	—		(68)		(138)		(206)
Balance at December 31, 2025	170,943	187,024	$	4,726	$	(278)	$	5,915	$	10,363

(1)The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero during the periods presented.

See accompanying notes to consolidated financial statements.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy, Inc. is a publicly traded Delaware corporation. Viper (as defined below) and its consolidated subsidiaries are focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin.

On August 19, 2025, upon completion of the Sitio Acquisition (as defined and discussed in Note 4—Acquisitions and Divestitures), VNOM Sub, Inc. (formerly known as Viper Energy Inc., “Former Viper”) became a wholly owned subsidiary of Viper Energy, Inc. (formerly known as New Cobra Pubco, Inc., “New Viper”), as a result of a merger contemplated by the documents governing the Sitio Acquisition (such merger, the “Viper PubCo Merger”).

Upon completion of the Viper PubCo Merger, each share of Former Viper’s Class A common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger (other than certain excluded shares) was canceled and automatically converted into one share of New Viper Class A common stock, par value $0.000001 per share (“New Viper Class A Common Stock”), and each share of Former Viper’s Class B common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger was automatically canceled and converted into one share of New Viper’s Class B common stock, par value $0.000001 per share (“New Viper Class B Common Stock”).

As of December 31, 2025, Viper, through its subsidiaries, owned approximately 46.5% of the outstanding OpCo Units and was the managing member of New OpCo.

Prior to March 8, 2024, the Company was a “controlled company” under the rules of the Nasdaq Stock Market LLC (the “Nasdaq Rules”). On March 8, 2024, the Company’s parent, Diamondback (as defined below), completed an underwritten public offering in which it sold 13,225,000 shares of the Company’s Class A Common Stock (the “Diamondback Offering”). Following the Diamondback Offering, Diamondback’s beneficial ownership was reduced to less than 50% of the Company’s total Common Stock outstanding. As such, the Company ceased to be a “controlled company” under the Nasdaq Rules. Prior to the Diamondback Offering, the Company’s board of directors had a majority of independent directors and a standing audit committee comprised of all independent directors, but had elected to take advantage of certain exemptions from corporate governance requirements applicable to controlled companies under the Nasdaq Rules and, until March 8, 2024, did not have a compensation committee or a committee of independent directors that selects director nominees.

Effective as of March 8, 2024, the Company’s board of directors formed (i) the compensation committee for purposes of making certain executive and other compensation decisions, and (ii) the nominating and corporate governance committee for purposes of making certain nominating and corporate governance decisions, with each such committee’s rights and obligations being subject to the terms and conditions of (x) the Company’s certificate of incorporation, (y) such committee’s charter as adopted by the board, and (z) the services and secondment agreement, dated as of November 2, 2023, pursuant to which Diamondback provides personnel and general and administrative services to the Company, including the services of the executive officers and other employees (the “Services and Secondment Agreement”).

Subsequent transactions completed in 2025 have resulted in Diamondback temporarily owning more than or less than 50% of the Company’s Common Stock causing changes in the Company’s status as a “controlled company” under the applicable Nasdaq Rules. While the controlled company exemptions were at times again available to the Company, the Company’s board of directors did not avail itself of these exemptions. As of December 31, 2025, Diamondback beneficially owned approximately 42.1% of the outstanding voting power of the Company’s Common Stock, on a fully diluted basis after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4—Acquisitions and Divestitures).

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Conversion into Corporation

Effective November 13, 2023, (the “Effective Time”), Viper Energy Partners LP converted from a publicly traded Delaware limited partnership to a Delaware corporation pursuant to a plan of conversion and changed its name from Viper Energy Partners LP to Viper Energy, Inc. Additionally, the certificate of incorporation and the bylaws of Viper Energy, Inc. became effective on the same date. This report includes the results for the Partnership prior to the Conversion and the Company following the Conversion. There are no tax impacts resulting from the Conversion as the Partnership was treated as a corporation for tax purposes.

At the Effective Time, (i) each common unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A Common Stock, (ii) each Class B unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B Common Stock, and (iii) the general partner interest issued and outstanding immediately prior to the Effective Time (100% owned by the General Partner) was cancelled.

At the Effective Time, the Company’s certificate of incorporation and bylaws generally provided its stockholders with substantially the same or greater rights and substantially the same or lesser obligations, as those that limited partners had in the Partnership Agreement. Previously, limited partners were not generally entitled to vote with respect to governance of the Partnership, except for those few matters set forth in the Partnership Agreement. Following the Conversion, except as otherwise expressly provided in the Company’s certificate of incorporation, the holders of Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the General Corporation Law of the State of Delaware, including the election of the board of directors of the Company.

Diamondback continues to provide personnel and general and administrative services to the Company, including the services of the executive officers and other employees, pursuant to the Services and Secondment Agreement. In addition, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of the outstanding Common Stock of the Company, (i) Diamondback will have the right to designate up to three persons to serve as directors of the Company, and (ii) the board of directors of the Company may not appoint any person other than a Diamondback seconded employee as an executive officer of the Company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned), or (y) the affirmative vote of the holders of at least 80% of the voting power of the capital stock of the Company. Currently, there are two Diamondback designees to the board of directors of the Company—Travis Stice and Kaes Van’t Hof.

References in the accompanying consolidated financial statements and related notes thereto to “Viper” refer to (A) New Viper following the Viper PubCo Merger, (B) Former Viper prior to the Viper PubCo Merger, but after the Conversion, and (C) Viper Energy Partners LP prior to the Conversion. References to the “Company,” “our company,” “we,” “our,” “us” or like terms refer collectively to Viper and its consolidated subsidiaries. References to “shares” or per share amounts prior to the Conversion refer to common units and Class B units or per unit amounts of Viper Energy Partners LP. References to shares or per share amounts following the Conversion refer to (A) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of New Viper following the Viper PubCo Merger and (B) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of Former Viper prior to the Viper PubCo Merger.

References to the “Operating Company” or “OpCo” refer to (A) New OpCo following the Reorganization and (B) Old OpCo prior to the Reorganization. References to “OpCo Units” are to the units representing limited liability company interests in the Operating Company.

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation. The Company reports its operations in one reportable segment.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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.

Revenue from Contracts with Customers

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.

Royalty Income from Oil, Natural Gas and Natural Gas Liquids Sales

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.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Transaction Price Allocated to Remaining Performance Obligations

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.

Contract Balances

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.

Prior-Period Performance Obligations

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.

Oil and Natural Gas Properties

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

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

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 Receivable

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.

Concentrations

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.

Related Party Transactions

Royalty Income Receivable

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.

Lease Bonus Income

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.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Other Related Party Transactions

See Note 4—Acquisitions and Divestitures for significant related party acquisitions of oil and natural gas interests.

See Note 7—Stockholders’ Equity for further details regarding equity transactions with related parties.

All other related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements or were insignificant for the years ended December 31, 2025, 2024 and 2023, respectively.

Derivative Instruments

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.”

Income Taxes

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

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

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.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Derivative instruments	$	28	$	18
Prepaid expenses	13		11
Other	9		2
Total prepaid expenses and other current assets	$	50	$	31

See “—Derivative Instruments” above for the Company’s accounting policy for derivative instruments.

Accrued Liabilities

The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value.

Accrued liabilities consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Interest payable	$	39	$	10
Ad valorem taxes payable	34		20

Acquisition adjustment accrual	4		9
2026 WTI Contingent Liability	20		—
Other	10		4
Total accrued liabilities	$	107	$	43

Debt Issuance Costs

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.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

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

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Notes to Consolidated Financial Statements - (Continued)

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.

Accounting Pronouncements Not Yet Adopted

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.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained from third-party purchasers 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 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. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

For the years ended December 31, 2025, 2024 and 2023, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods were not material.

The following tables disaggregate the Company’s revenue from oil, natural gas and natural gas liquids by revenue generated from production on properties operated by Diamondback and revenue generated from production on properties operated by third parties:


	Year Ended December 31, 2025
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	612	$	519	$	1,131
Natural gas income	31		25		56
Natural gas liquids income	98		61		159
Total royalty income	$	741	$	605	$	1,346


	Year Ended December 31, 2024
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	398	$	352	$	750
Natural gas income	10		5		15
Natural gas liquids income	51		38		89
Total royalty income	$	459	$	395	$	854

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Notes to Consolidated Financial Statements - (Continued)


	Year Ended December 31, 2023
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	377	$	242	$	619
Natural gas income	16		15		31
Natural gas liquids income	42		25		67
Total royalty income	$	435	$	282	$	717

4. ACQUISITIONS AND DIVESTITURES

2025 Activity

Sitio Acquisition

On August 19, 2025, the Company completed a series of transactions in which New Viper acquired Sitio Royalties Corp. (“Sitio”), Sitio OpCo and their respective subsidiaries, pursuant to the Agreement and Plan of Merger, dated June 2, 2025, by and among Former Viper, the Operating Company, Sitio, Sitio OpCo, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (the “Sitio Acquisition”). The Sitio Acquisition was an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The Company funded the retirement of Sitio’s net debt through a combination of cash on hand, proceeds from the issuance of the Guaranteed Senior Notes and borrowings under the Term Loan (as defined and discussed in Note 6—Debt).

Equity consideration for the Sitio Acquisition consisted of the right for Sitio and Sitio OpCo’s former equity holders to receive (i) 0.4855 shares of New Viper Class A Common Stock, for each share of Sitio Class A common stock, par value $0.0001 per share, and (ii) 0.4855 OpCo Units, along with a corresponding amount of New Viper Class B Common Stock, for each unit representing limited partnership interests of Sitio OpCo, subject to certain exclusions. The OpCo Units and New Viper Class B Common Stock issued in the Sitio Acquisition are exchangeable from time to time for shares of New Viper Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). Each share of Class C common stock, par value $0.0001 per share, of Sitio was automatically canceled in the transaction for no consideration and ceased to exist upon closing of the Sitio Acquisition. The shares of common stock of Former Viper and Sitio were delisted from the Nasdaq and their respective reporting obligations under the Exchange Act were terminated. As part of the Sitio Acquisition, New Viper issued 38,536,236 shares of Class A Common Stock, 35,619,951 shares of Class B Common Stock and 35,619,951 OpCo Units. In addition, at the closing of the Sitio Acquisition, the Company entered into a registration rights agreement with certain of Sitio OpCo’s former equity holders, pursuant to which such equity holders received certain demand registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock.

The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres. See Note 13—Subsequent Events for discussion of divestiture of the non-Permian acreage in 2026.

The Sitio Acquisition was accounted for as an asset acquisition in accordance with ASC 805.

2025 Drop Down

On May 1, 2025, the Company acquired all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC from Endeavor Energy Resources, LP (“Endeavor”), each a seller party and a subsidiary of Diamondback, pursuant to a definitive equity purchase agreement for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of the Company’s Class B Common Stock (the “2025 Drop Down”). The OpCo Units and the Class B Common Stock issued in the 2025 Drop Down, as well as the OpCo Units and Class B Common Stock otherwise beneficially owned by

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Diamondback, are exchangeable from time to time for shares of the Company’s Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). The shares of Class A Common Stock that may be issued to Diamondback and/or its subsidiaries upon exchange of their OpCo Units and shares of Class B Common Stock, including those OpCo Units and shares of Class B Common Stock issued at the closing of the 2025 Drop Down, are subject to the Company’s existing registration rights agreement with Diamondback, dated as of November 13, 2023, previously filed by the Company with the SEC.

The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback, and have an average net royalty interest of approximately 2.2% and then-current oil production of approximately 17,097 BO/d (the “Endeavor Mineral and Royalty Interests”). The Endeavor Mineral and Royalty Interests include interests in horizontal wells comprised of 5,574 gross proved developed production wells (of which approximately 32% are operated by Diamondback), 116 gross completed wells and 394 gross drilled but uncompleted wells, all of which are principally concentrated in the Midland Basin, with the balance located primarily in the Delaware and Williston Basins.

The 2025 Drop Down was approved by (i) the Company’s audit committee comprised of all independent directors and the full board of directors, in each case on January 30, 2025, and (ii) the majority of the Company’s stockholders, other than Diamondback and its subsidiaries, at the special meeting of the Company’s stockholders held on May 1, 2025, as required under the Nasdaq Rules.

The Company funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the 2025 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity) and borrowings under our previous revolving credit facility. The 2025 Drop Down was accounted for as a transaction between entities under common control, with the Endeavor Mineral and Royalty Interests recorded at Endeavor’s historical carrying value in the Company’s consolidated balance sheet.

Morita Ranches Acquisition

On February 14, 2025, the Company completed an acquisition of certain mineral and royalty interests located in Howard County, Texas from Morita Ranches Minerals, LLC (“Morita Ranches”) (the “Morita Ranches Acquisition”) pursuant to a definitive purchase and sale agreement for consideration consisting of approximately (i) $208 million in cash, and (ii) 2,400,297 OpCo Units together with an equal number of shares of the Company’s Class B Common Stock issued to certain affiliate designees of Morita Ranches (the “Morita Ranches Equity Recipients”), including customary transaction costs and post-closing adjustments. At the closing of the Morita Ranches Acquisition, the Morita Ranches Equity Recipients (i) became parties to the Third Amended and Restated Limited Liability Agreement of the Operating Company, dated as of October 1, 2024, as amended, and (ii) entered into an Exchange Agreement with the Company and the Operating Company to provide for the right to exchange the OpCo Units and shares of the Company’s Class B Common Stock acquired by the Morita Ranches Equity Recipients at the closing of the Morita Ranches Acquisition for an equal number of shares of the Company’s Class A Common Stock. In addition, at the closing of the Morita Ranches Acquisition, the Company entered into a registration rights agreement pursuant to which the Morita Ranches Equity Recipients received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock.

The mineral and royalty interests included in the Morita Ranches Acquisition represent approximately 1,691 net royalty acres in the Permian Basin, 75% of which are operated by Diamondback, and have an average net royalty interest of approximately 10.9%. The Company funded the cash consideration for the Morita Ranches Acquisition with proceeds from the 2025 Equity Offering. The Morita Ranches Acquisition was accounted for as an asset acquisition in accordance with ASC 805.

Other Acquisitions

During the year ended December 31, 2025, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $140 million, including customary closing adjustments. In the second half of 2025, the Company acquired, in individually insignificant transactions from Diamondback E&P LLC, mineral and royalty interests representing 80 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $2 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our revolving credit facility.

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2024 Activity

Acquisitions

Tumbleweed Acquisitions

In September and October of 2024, the Company completed a series of related acquisitions including the TWR Acquisition, the Q Acquisition and the M Acquisition (collectively the “Tumbleweed Acquisitions”), each as defined and discussed below.

TWR Acquisition

On October 1, 2024, the Company acquired all of the issued and outstanding equity interests in TWR IV, LLC and TWR IV SellCo, LLC from TWR IV and TWR IV SellCo Parent, LLC (the “TWR Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $464 million in cash, including transaction costs and certain customary post-closing adjustments, (ii) 10,093,670 OpCo Units to TWR IV, (iii) an option granted to TWR IV to acquire up to 10,093,670 shares of the Company’s Class B Common Stock (the “TWR Class B Option”), and (iv) contingent cash consideration of $16 million paid in January 2026 (the “TWR Contingent Liability”) based on the average price of WTI sweet crude oil prompt month futures contracts for the calendar year 2025 (the “WTI 2025 Average”), which was between $60.00 and $65.00. Additionally, at the closing of the TWR Acquisition, the Company assumed a royalty income receivable of approximately $24 million.

TWR IV can exchange some or all of its OpCo Units for an equal number of shares of the Company’s Class A Common Stock and any OpCo Units so exchanged will reduce the number of shares of Class B Common Stock subject to the TWR Class B Option. In addition, at the closing of the TWR Acquisition, the Company entered into a registration rights agreement with TWR IV, pursuant to which TWR IV received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by TWR IV in exchange for OpCo Units. The mineral and royalty interests acquired in the TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin. The Company funded the cash consideration for the TWR Acquisition through a combination of cash on hand, borrowings under our previous revolving credit facility and proceeds from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity).

Q Acquisition

On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (the “Q Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “Q Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the Q Acquisition represent approximately 406 net royalty acres located primarily in the Permian Basin. The cash consideration for the Q Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility.

M Acquisition

On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in MC TWR Royalties, LP and MC TWR Intermediate, LLC (the “M Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “M Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the M Acquisition represent approximately 267 net royalty acres located primarily in the Permian Basin. The cash consideration for the M Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility.

The Q Contingent Liability, the M Contingent Liability and the TWR Contingent Liability are collectively referred to as the “2026 WTI Contingent Liability.”

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Other Acquisitions

In addition to the acquisitions discussed above, during the year ended December 31, 2024, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 261 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $54 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility.

Divestiture

In the second quarter of 2024, the Company divested all of its non-Permian assets for a purchase price of approximately $87 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 2,713 net royalty acres with current production of approximately 450 BO/d. The Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale.

2023 Activity

Acquisitions

GRP Acquisition

On November 1, 2023, the Company acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP, affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement for 9,018,760 common units and $747 million in cash, including transaction costs and certain customary post-closing adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired in the GRP Acquisition represent approximately 4,600 net royalty acres in the Permian Basin, and approximately 2,700 additional net royalty acres in other major basins. The cash consideration for the GRP Acquisition was funded through a combination of cash on hand and held in escrow, borrowings under our previous revolving credit facility, proceeds from the 2031 Notes (as defined and discussed in Note 6—Debt) and proceeds from the $200 million common unit issuance to Diamondback discussed further in Note 7—Stockholders’ Equity.

2023 Drop Down

On March 8, 2023, the Company acquired certain mineral and royalty interests from subsidiaries of Diamondback for approximately $75 million in cash, including customary closing adjustments for net title benefits (the “2023 Drop Down”). The mineral and royalty interests acquired in the 2023 Drop Down represented approximately 660 net royalty acres in Ward County, Texas in the Southern Delaware Basin, 100% of which were operated by Diamondback, and had an average net royalty interest of approximately 7.2% and then-current production of approximately 300 BO/d. The Company funded the 2023 Drop Down through a combination of cash on hand and borrowings under our previous revolving credit facility. The 2023 Drop Down was accounted for as a transaction between entities under common control with the acquired properties recorded at Diamondback’s historical carrying value in the Company’s consolidated balance sheet. The historical carrying value of the properties approximated the 2023 Drop Down purchase price.

Other Acquisitions

Additionally during the year ended December 31, 2023, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 286 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $70 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility.

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5. OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following for the periods presented:


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved properties	$	9,746	$	3,533
Unproved properties	4,910		2,180
Gross oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Oil and natural gas interests, net	12,201		4,632
Other property, equipment and land	8		6
Property, net of accumulated depletion and impairment	$	12,209	$	4,638

Balance of costs not subject to depletion:
Incurred in 2025	$	3,614
Incurred in 2024	562
Incurred in 2023	553
Prior	181
Total not subject to depletion	$	4,910

As of December 31, 2025, and 2024, the Company had mineral and royalty interests representing approximately 96,003 and 35,671 net royalty acres, respectively.

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves can be made. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within nine to 12 years. All costs incurred not subject to depletion are classified as acquisition costs.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. As a result of its ceiling test, the Company recorded aggregate non-cash ceiling test impairments for the year ended December 31, 2025 of $768 million. No impairment expense was recorded on the Company’s oil and natural gas interests for the years ended December 31, 2024 and 2023, based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Company’s production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If future SEC Prices decline as compared to the commodity prices used in prior quarters, the Company could have further write-downs in subsequent quarters, which may be material.

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6. DEBT

Long-term debt consisted of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
5.375% Senior Notes due 2027	$	—	$	430
4.900% Senior Notes due 2030	500		—
7.375% Senior Notes due 2031	—		400
5.700% Senior Notes due 2035	1,100		—
Term Loan	500		—
Revolving credit facility	105		261
Unamortized debt issuance costs	(15)		(6)
Unamortized discount costs	(4)		(2)
Total long-term debt	$	2,186	$	1,083

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent (the “2025 Revolving Credit Facility”), which among other things, provides the borrower with a senior unsecured revolving credit facility with a commitment of $1.5 billion, a swingline commitment of up to $50 million and a letter of credit commitment of $5 million. The 2025 Revolving Credit Facility has a maturity date of June 12, 2030, with the ability to request three extensions of the maturity date by one year. The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the borrower, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced the borrower’s previous revolving credit facility, dated July 20, 2018, among the Company, the borrower and Wells Fargo as amended, restated, amended and restated, supplemented or otherwise modified prior to June 12, 2025. As of December 31, 2025, there was $105 million in outstanding borrowings and $1.4 billion available for future borrowings under the 2025 Revolving Credit Facility. For the years ended December 31, 2025, 2024 and 2023, the weighted average interest rates on borrowings under the borrower’s respective revolving credit facilities were 6.02%, 7.34%, and 7.41%, respectively.

Borrowings under the 2025 Revolving Credit Facility bear interest at a per annum rate elected by the borrower that is equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate loans and from 1.125% to 2.000% per annum in the case of term SOFR loans, in each case based on the pricing level. Further, the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitment, again based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies.

The 2025 Revolving Credit Facility contains a financial covenant that requires the Company to maintain a Total Net Debt to Capitalization Ratio (as defined in the 2025 Revolving Credit Facility) of no more than 65%. As of December 31, 2025, the borrower was in compliance with all financial maintenance covenants under the 2025 Revolving Credit Facility.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which thereupon became the borrower with respect to the 2025 Revolving Credit Facility.

Term Loan

On July 23, 2025, in connection with the Sitio Acquisition, Former Viper, as guarantor, entered into a term loan credit agreement with the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, (the “Term Loan”).

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The Term Loan provided the Company with the ability to borrow up to $500 million on a senior unsecured basis to fund a portion of the retirement of Sitio’s net debt, in connection with the Sitio Acquisition. On August 19, 2025, the date of closing of the Sitio Acquisition, the Term Loan was fully drawn in a single borrowing. Any then-outstanding amounts will mature and be payable in full on the second anniversary of the initial funding date. In connection with the closing of the Sitio Acquisition, New Viper became a co-guarantor of the Term Loan. During the year ended December 31, 2025, the weighted average interest rate on borrowings under the Term Loan was 5.72%.

Borrowings under the Term Loan bear interest at a per annum rate elected by the borrower that is equal to SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies. In addition, the fee on undrawn commitments is equal to 0.20% per annum on the aggregate principal amount of such commitments.

Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

Guaranteed Senior Notes Offering

On July 23, 2025, the Operating Company, as issuer, and Former Viper, as guarantor, issued $1.6 billion in aggregate principal amount of the Guaranteed Senior Notes consisting of (i) $500 million aggregate principal amount of 4.900% Senior Notes due August 1, 2030, (the “2030 Notes”), and (ii) $1.1 billion aggregate principal amount of 5.700% Senior Notes due August 1, 2035, (the “2035 Notes”). The Company received net proceeds of approximately $1.58 billion, after underwriters’ discounts and transaction costs. Interest on the Guaranteed Senior Notes is payable semi-annually in February and August of each year, beginning on February 1, 2026. Concurrently, the Company used approximately $824 million of the proceeds to redeem approximately $780 million in aggregate principal amounts of the Company’s outstanding Notes, including accrued interest due and applicable redemption premiums. Following the closing of the Sitio Acquisition, the Company used the remaining proceeds from the issuance of the Guaranteed Senior Notes to (i) retire Sitio’s 7.875% senior notes due 2028, (ii) partially repay borrowings under Sitio’s revolving credit facility, (iii) pay fees, costs and expenses related to the redemption or repayment of such debt, and (iv) for general corporate purposes.

The Guaranteed Senior Notes (i) are senior unsecured obligations and are fully and unconditionally guaranteed by Former Viper, and, following the closing of the Sitio Acquisition, also by New Viper, (ii) are senior in right of payment to any of the Company’s future subordinated indebtedness, and (iii) rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The Guaranteed Senior Notes have been registered under the Securities Act.

Following the OpCo Conversion, Viper LP became the issuer with respect to the Guaranteed Senior Notes.

Retirement of Notes

During the second quarter of 2025, the Company opportunistically repurchased principal amounts of $50 million of its 5.375% Senior Notes due 2027 (the “2027 Notes”) in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value, resulting in an immaterial gain on extinguishment of debt for the year ended December 31, 2025.

On July 23, 2025, using proceeds from the issuance of the Guaranteed Senior Notes, the Company (i) redeemed all of its outstanding 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”), which were issued in October 2023 to partially fund the cash portion of the GRP Acquisition, for total cash consideration of approximately $434 million including the applicable redemption premium of 106.767% of par and accrued and unpaid interest up to, but not including, the redemption date, and (ii) deposited approximately $390 million to redeem all of its outstanding 2027 Notes on November 1, 2025, for total cash consideration, including payment of interest due to, but not including, the redemption date at a redemption price equal to 100% of the principal amount of the 2027 Notes. The redemption of the 2031 Notes resulted in a loss on extinguishment of debt of $32 million.

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Notes to Consolidated Financial Statements - (Continued)

Interest Expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2025, 2024 and 2023:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Interest expense	$	103	$	74	$	48
Other fees and expenses	3		2		1
Less: interest income	10		2		2


Interest expense, net	$	96	$	74	$	47

7. STOCKHOLDERS’ EQUITY

At December 31, 2025, the Company had a total of 170,942,687 shares of Class A Common Stock issued and outstanding and 187,023,698 shares of Class B Common Stock issued and outstanding. Additionally, at December 31, 2025, TWR IV held the TWR Class B Option to acquire up to 10,093,670 shares of the Company’s Class B Common Stock.

In connection with the Reorganization, Viper in its position as managing member of New OpCo, along with affiliates of Diamondback, TWR IV and the Morita Ranches Equity Recipients adopted the Amended and Restated Limited Liability Company Agreement of New OpCo (the “New OpCo LLC Agreement”). The New OpCo LLC Agreement provides that members of New OpCo may require the Company to redeem all or a portion of the shares of the Company’s Class B Common Stock held by such member, together with an equal number of OpCo Units (one share of Class B Common Stock together with one OpCo Unit) in exchange for (i) an equivalent number of shares of the Company’s Class A Common Stock, or (ii) cash consideration subject to the terms and conditions included in the New OpCo LLC Agreement.

The following table presents the beneficial ownership of Common Stock and OpCo Units as of December 31, 2025:


	As of December 31, 2025
	Shares of Common Stock Beneficially Owned	Percentage Ownership(1)		OpCo Units Beneficially Owned	Percentage Ownership
Public equity holders of Class A Common Stock	170,942,687	46.5	%	—	—	%
Viper and subsidiaries	—	—	%	170,942,687	46.5	%
Diamondback and subsidiaries	155,058,093	42.1	%	155,058,093	42.1	%
Sitio OpCo former equity holders	29,565,308	8.0	%	29,565,308	8.0	%
TWR IV(1)	10,093,670	2.7	%	10,093,670	2.7	%
Morita Ranches Equity Recipients	2,400,297	0.7	%	2,400,297	0.7	%
Total Ownership(1)	368,060,055	100.0	%	368,060,055	100.0	%

(1)On a fully diluted basis, assuming TWR IV exercises the TWR Class B Option.

2025 Equity Offering

On February 3, 2025, the Company completed an underwritten public offering of 28,336,000 shares of Class A Common Stock, which included 3,696,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $44.50 per share for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “2025 Equity Offering”). The Company used the net proceeds from the 2025 Equity Offering to fund (i) the cash consideration for the Morita Ranches Acquisition, (ii) a portion of the cash consideration for the 2025 Drop Down, and (iii) for general corporate purposes.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

2024 Equity Offering

On September 13, 2024, the Company completed an underwritten public offering of 11,500,000 shares of Class A Common Stock, which included 1,500,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $42.50 per share for total net proceeds of approximately $476 million, after the underwriters’ discount and transaction costs (the “2024 Equity Offering”). The net proceeds were used to fund a portion of the cash consideration for the TWR Acquisition.

2023 Viper Issuance of Common Units to Diamondback

In October 2023, the Company issued 7,215,007 of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200 million. The net proceeds were used to fund a portion of the cash consideration for the GRP Acquisition. During 2024, Diamondback sold all of its shares of the Company’s Class A Common Stock in the Diamondback Offering discussed in Note 1—Organization and Basis of Presentation.

Repurchase Program

Previously, the Company’s board of directors authorized a $750 million repurchase program, with respect to the repurchase of the Company’s Class A Common Stock, excluding excise tax, over an indefinite period of time. On December 10, 2025, the Company’s board of directors expanded the repurchase program to also include repurchases of the Company’s Class B Common Stock and OpCo Units. The Company has purchased and intends to continue to purchase shares of Common Stock and OpCo Units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended, modified or extended, from time to time, or may be discontinued at any time, in each case, by the Company’s board of directors.

During the year ended December 31, 2025, repurchases under the repurchase program totaled $194 million, which includes approximately $41 million for the repurchase of 1,000,000 OpCo Units from an affiliate of Kimmeridge Energy Management Company, LLC (“Kimmeridge”) in a privately negotiated transaction on December 10, 2025. Concurrently, a corresponding number of shares of the Company’s Class B Common Stock owned by Kimmeridge were cancelled. During the year ended December 31, 2024, there were no repurchases under the repurchase program. Repurchases of $95 million for the year ended December 31, 2023, include approximately $29 million for the repurchase of 1,000,000 shares of Class A Common Stock from GRP in a privately negotiated transaction in the fourth quarter of 2023. As of December 31, 2025, $241 million remains available under the repurchase program, excluding excise tax.

Cash Dividends

The board of directors of the Company has established a dividend policy, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to holders of the OpCo Units. Viper in turn distributes all or a portion of the available cash it receives from the Operating Company to holders of its Class A Common Stock through base and variable dividends that take into account capital returned to stockholders via its repurchase program. The Company’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors following the end of such quarter. The Company’s dividend policy currently requires the Company to pay quarterly variable dividends of at least 75% of its available cash less the base dividend declared and the amount paid for repurchases of the Company’s Common Stock and OpCo Units as part of its repurchase program for the applicable quarter. Additionally, the Company’s board of directors may approve certain one-time discretionary adjustments to the calculation of cash available for distribution.

The Company expects that its available cash will generally equal the Adjusted EBITDA attributable to the Company for the applicable quarter, less cash needed for income taxes payable; debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the Company’s board of directors deems necessary or appropriate; lease bonus income (net of applicable taxes); dividend equivalent rights payments; preferred distributions and an adjustment for changes in ownership interests that occurred subsequent to the quarter, if any.

The percentage of cash available for distribution by the Operating Company pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Company’s balance sheet while also expanding the return of capital program through the Company’s repurchase program. The Company is not required to pay dividends to the holders of its Class A Common Stock on a quarterly or other basis.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

The Company is also required to pay a quarterly preferred dividend in respect of its Class B Common Stock in the aggregate amount of $20,000 per quarter, which is consistent with the Partnership’s pre-Conversion preferred distribution requirement. Other than the preferred dividend requirement, the Company is not required to pay dividends to the holders of its Common Stock on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of the Company’s board of directors.

The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2025, 2024 and 2023 (in millions except per share amounts):


	Distributions
Period	Amount per OpCo Unit		Operating Company Distributions to Non-Controlling Interests		Amount per Class A Common Share		Class A Common Stockholders(1)(2)		Declaration Date	Class A Common Stockholder Record Date	Payment Date
2025
Q4 2024	$	0.69	$	68	$	0.65	$	85	January 30, 2025	March 6, 2025	March 13, 2025
Q1 2025	$	0.70	$	117	$	0.57	$	75	May 1, 2025	May 15, 2025	May 22, 2025
Q2 2025	$	0.59	$	98	$	0.53	$	68	July 31, 2025	August 14, 2025	August 21, 2025
Q3 2025	$	0.66	$	134	$	0.58	$	99	October 30, 2025	November 13, 2025	November 20, 2025
2024
Q4 2023	$	0.69	$	63	$	0.56	$	48	February 15, 2024	March 5, 2024	March 12, 2024
Q1 2024	$	0.70	$	60	$	0.59	$	54	April 25, 2024	May 15, 2024	May 22, 2024
Q2 2024	$	0.76	$	65	$	0.64	$	59	August 1, 2024	August 15, 2024	August 22, 2024
Q3 2024	$	0.73	$	69	$	0.61	$	63	October 31, 2024	November 14, 2024	November 21, 2024
2023
Q4 2022	$	0.54	$	49	$	0.49	$	36	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38	$	0.33	$	24	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	40	$	0.36	$	25	July 25, 2023	August 10, 2023	August 17, 2023
Q3 2023	$	0.70	$	64	$	0.57	$	49	November 2, 2023	November 16, 2023	November 24, 2023

(1)Dividends paid in the first quarter of 2024 include amounts paid to Diamondback for the 7,946,507 shares of Class A Common Stock then beneficially owned by Diamondback and distributions equivalent rights payments. As of March 31, 2024, Diamondback did not beneficially own any shares of Class A Common Stock.

(2)For distributions paid in 2023, includes amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback.

Cash dividends will be made to the holders of record of the Company’s Class A Common Stock on the applicable record date, generally within 60 days after the end of each quarter.

Changes in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, Sitio OpCo’s former equity holders, TWR IV and the Morita Ranches Equity Recipients in the net assets of the Operating Company. The non-controlling interests’ relative ownership in the Operating Company can change due to the purchase or sale of the Company’s Common Stock, the Company’s public offerings of shares of Class A Common Stock for which proceeds are contributed to the Operating Company in exchange for OpCo Units, issuance of shares of Class A Common Stock or issuance of shares of Class B Common Stock and OpCo Units for acquisitions, share-based compensation, repurchases of shares of Common Stock or OpCo Units and dividend equivalent rights paid on the Company’s Class A Common Stock. These changes in ownership percentage result in adjustments to non-controlling interest and stockholders’ equity, tax effected, but do not impact earnings.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Net income (loss) attributable to the Company	$	(68)	$	359	$	200
Change in ownership of consolidated subsidiaries	448		59		(102)
Change from net income (loss) attributable to the Company’s stockholders and transfers with non-controlling interest	$	380	$	418	$	98

8. EARNINGS PER COMMON SHARE

The net income (loss) per common share on the consolidated statements of operations is based on the net income (loss) attributable to the Company’s Class A Common Stock for the years ended December 31, 2025, 2024 and 2023.

Basic and diluted earnings per common share are calculated using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of Class A Common Stock and participating securities. Basic net income (loss) per common share is calculated by dividing net income (loss) by the weighted-average shares of Class A Common Stock outstanding during the period. Diluted net income (loss) per common share gives effect, when applicable, to unvested restricted stock units and performance restricted stock units granted under the LTIP.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:


	Year Ended December 31,
	2025		2024		2023
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to the period	$	(68)	$	359	$	200
Less: net income (loss) allocated to participating securities(1)	1		—		—
Net income (loss) attributable to common stockholders	$	(69)	$	359	$	200
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	142,530		93,932		74,176
Effect of dilutive securities:
Potential common shares issuable(2)	—		—		—
Diluted weighted average common shares outstanding	142,530		93,932		74,176
Net income (loss) per common share, basic	$	(0.48)	$	3.82	$	2.69
Net income (loss) per common share, diluted	$	(0.48)	$	3.82	$	2.69

(1)Unvested restricted stock units and performance restricted stock units that contain non-forfeitable dividend equivalent rights are considered participating securities and are therefore included in the earnings per share calculation pursuant to the two-class method.

(2)For the year ended December 31, 2025, 110,342 potential common shares were excluded from the computation of diluted earnings per common share because their inclusion would have been anti-dilutive as a result of recording a net loss attributable to the common shareholders for the period. For the years ended December 31, 2024 and 2023 no significant potential common shares were excluded from the computation of diluted earnings per common share.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

9. INCOME TAXES

The Company’s total income tax benefit for the year ended December 31, 2025, differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to net loss attributable to the non-controlling interest. For the year ended December 31, 2024, the Company’s total income tax benefit differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the release of the remaining valuation allowance during the fourth quarter and net income attributable to non-controlling interests. For the year ended December 31, 2023, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of reductions to the valuation allowance.

The components of the provision for income taxes for the years ended December 31, 2025, 2024 and 2023 are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Current income tax provision (benefit):
Federal	$	60	$	47	$	50
State	4		2		3
Total current income tax provision (benefit)	64		49		53
Deferred income tax provision (benefit):
Federal	(78)		(148)		(7)
State	(5)		(1)		—
Total deferred income tax provision (benefit)	(83)		(149)		(7)
Total provision (benefit) from income taxes	$	(19)	$	(100)	$	46

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:


	Year Ended December 31,
	2025				2024				2023
	Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes
Income tax expense (benefit) at the federal statutory rate (21%)	$	(47)	21	%	$	106	21	%	$	115	21	%


State income tax, net of federal income tax effect(1)	(1)		—	%	2		—	%	2		—	%


Changes in valuation allowances	—		—	%	(156)		(31)	%	(8)		(1)	%

Nontaxable or nondeductible items:
Impact of nontaxable noncontrolling interest	29		(13)	%	(52)		(10)	%	(63)		(12)	%
Provision for (benefit from) income taxes	$	(19)	8	%	$	(100)	(20)	%	$	46	8	%

(1)State taxes in Texas make up the majority (greater than 50%) of the tax effect in this category.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2025 and 2024 are as follows:


	Year Ended December 31,
	2025		2024
	(In millions)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	5	$	—
Investment in the Operating Company	28		185


Total deferred tax assets	33		185
Valuation allowance	—		—
Net deferred tax assets	33		185




Net deferred tax assets (liabilities)	$	33	$	185

At December 31, 2025, the Company had net deferred tax assets of approximately $33 million, including $5 million in federal capital loss carryforwards expiring in 2027 and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Company’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company.

In connection with the closing of the Sitio Acquisition, the Company acquired prepaid income tax balances of approximately $14 million and deferred tax assets of $5 million related to loss carryforwards. The Company also recognized a deferred tax liability of approximately $122 million. The Company’s federal loss carryforwards acquired from Sitio are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which subjects tax attributes to limitation upon an “ownership change” (as defined in the Code). In general, an ownership change occurs if there is a cumulative increase in the ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year look back period. Based on Sitio’s fair market value, the Company has determined that the applicable annual limitation exceeds the loss carryforwards acquired from Sitio. As such, the Company believes that the application of Section 382 of the Code will not have an adverse effect on future usage of its federal tax attributes.

During the fourth quarter of 2024, the Company released its remaining valuation allowance of $156 million as a result of management’s assessment of the realizability of future taxable income, which primarily contributed to the discrete income tax benefit of $149 million for the year ended December 31, 2024. During the year ended December 31, 2023, the Company recognized a discrete income tax benefit of $7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years.

In March 2024, as part of the Diamondback Offering, the Company recognized a $28 million increase in its deferred tax asset and an $11 million increase in its valuation allowance through additional paid-in capital.

At December 31, 2025, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The Company’s 2022 through 2025 tax years remain open to examination by tax authorities.

On July 4, 2025, H.R. 1, commonly known as the One Big Beautiful Bill Act (the “OBBB”), was enacted. The OBBB included multiple provisions applicable to U.S. income taxes for businesses, including immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the corporate “book” minimum tax and enhancements to limits on business interest expense deductions. The Company accounted for the OBBB in the period of enactment and concluded there was not a material impact to the Company’s current or deferred income tax balances.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

10. DERIVATIVES

Commodity Contracts

The Company historically has used fixed price swap contracts, fixed price basis swap contracts, deferred premium puts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2025, the Company has puts, costless collars and fixed price basis swap contracts outstanding.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on WTI Cushing and fixed price basis swaps for oil based on the spread between the WTI Cushing crude oil price and the Argus WTI Midland crude oil price. The Company’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the WTI Cushing oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Under the Company’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Company, and when the settlement price is above the ceiling price, the Company is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under the 2025 Revolving Credit Facility and our counterparties have been deemed an acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding commodity derivative contracts. Market risks involved in the Company’s use of derivative instruments relate to its potential inability to realize the benefits of any increases in commodity prices above the prices established by its derivative contracts.

As of December 31, 2025, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


					Swaps	Collars		Puts
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential	Weighted Average Floor Price	Weighted Average Ceiling Price	Strike Price	Deferred Premium
OIL
Jan. - Mar.	2026	Puts	40,000	WTI Cushing	$—	$—	$—	$51.75	$(1.56)
Apr. - Jun.	2026	Puts	20,000	WTI Cushing	$—	$—	$—	$48.13	$(1.35)
NATURAL GAS
Jan. - Dec.	2026	Basis Swaps	80,000	Waha Hub	$(1.61)	$—	$—	$—	$—
Jan. - Dec.	2027	Basis Swaps	40,000	Waha Hub	$(1.40)	$—	$—	$—	$—
Jan. - Dec.	2026	Costless Collar	60,000	Henry Hub	$—	$2.75	$6.64	$—	$—

Treasury Locks

During the third quarter of 2025, the Company entered into certain treasury lock contracts to reduce the forecasted interest rate risk associated with the issuance of the Guaranteed Senior Notes. The treasury locks were terminated and settled upon issuance of the Guaranteed Senior Notes with a gain of $3 million recognized under the caption “Gain (loss) on derivative instruments, net” on the consolidated statements of operations for the year ended December 31, 2025.

Contingent Liability

The change in fair value of the 2026 WTI Contingent Liability is recognized in “Gain (loss) on derivative instruments, net” on the Company’s consolidated statements of operations for the years ended December 31, 2025 and 2024.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	31	$	15	$	(26)
2026 WTI Contingent Liability	10		(4)		—
Treasury locks	3		—		—
Total	$	44	$	11	$	(26)

Net cash receipts (payments) on derivatives:
Commodity contracts	$	27	$	(3)	$	(13)

Treasury locks	3		—		—
Total	$	30	$	(3)	$	(13)

11. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s commodity derivative instruments and the 2026 WTI Contingent Liability.

The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third-party, the contracted notional volumes and time to maturity. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The fair value of the 2026 WTI Contingent Liability was estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.

The following tables provide (i) the consolidated balance sheet classification where the Company’s commodity derivative instrument assets and liabilities and 2026 WTI Contingent Liability are recorded, (ii) fair value measurement information, (iii) the gross amounts of recognized assets and liabilities, (iv) the amounts offset under master netting arrangements with counterparties, and (v) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2025, and December 31, 2024:


	As of December 31, 2025
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	37	$	—	$	37	$	(9)	$	28


Liabilities:
Other current liabilities	$	—	$	9	$	—	$	9	$	(9)	$	—
Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	20	$	—	$	20	$	—	$	20
Other long-term liabilities	$	—	$	7	$	—	$	7	$	—	$	7


	As of December 31, 2024
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	24	$	—	$	24	$	(6)	$	18



Liabilities:
Other current liabilities	$	—	$	8	$	—	$	8	$	(6)	$	2

Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	30	$	—	$	30	$	—	$	30

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:


	December 31, 2025				December 31, 2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
Debt	$	2,186	$	2,233	$	1,083	$	1,105

The fair values of our current or previous revolving credit facility, as applicable, and the Term Loan approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair values of the Notes and Guaranteed Senior Notes were determined using the quoted market price at each period end, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of the Company’s proved oil and natural gas interests to fair value when they are impaired or held for sale.

See Note 2—Summary of Significant Accounting Policies and Note 5—Oil and Natural Gas Interests for further discussion of non-recurring fair value adjustments.

Fair Value of Financial Assets

The Company has other financial instruments consisting of cash and cash equivalents, royalty income receivable, income tax receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

12. COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of any pending proceedings, disputes or claims and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

13. SUBSEQUENT EVENTS

Cash Dividend

On February 18, 2026, our board of directors approved an increase to the Company’s annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025. Our board of directors further approved a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case, payable on March 12, 2026, to holders of record at the close of business on March 5, 2026. The dividend on Class A Common Stock consists of a base quarterly dividend of $0.38 per share and a variable quarterly dividend of $0.14 per share.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under the Company’s existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax.

Divestiture of Non-Permian Assets

On February 9, 2026, the Company divested all of its non-Permian assets, including those acquired from Sitio, to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for net cash proceeds of approximately $617 million, subject to 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 current production of approximately 4,750 BO/d. Proceeds from the divestiture were used to (i) repay the Company’s $500 million Term Loan in full, (ii) fully repay $90 million of then-outstanding borrowings under the 2025 Revolving Credit Facility, and (iii) for general corporate purposes.

14. SEGMENT INFORMATION

As of December 31, 2025, the Company is managed on a consolidated basis as a single operating and reportable segment which is focused on owning and acquiring mineral and royalty interests primarily in the Permian Basin in West Texas. The Company’s operating segment primarily derives its revenue from customers through the receipt of royalty income on the sale of oil and natural gas products as well as other immaterial service contracts. See Note 3—Revenue from Contracts with Customers for further discussion of the Company’s sources of revenue.

The Company’s Chief Operating Decision Maker (“CODM”) is a senior executive committee that is comprised of the Company’s Chief Executive Officer and President. The CODM uses the Company’s consolidated financial results to assess performance, allocate resources and make key operating decisions, obtaining the board’s approval as required. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets, as reported on the consolidated statements of operations and the consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s consolidated statements of operations as well as interest income and interest expense in Note 6—Debt.

The CODM uses consolidated net income as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or return of capital through the payment of base and variable dividends or repurchases under the share repurchase program.

15. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved	$	9,746	$	3,533
Unproved	4,910		2,180
Total oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Net oil and natural gas interests capitalized	$	12,201	$	4,632

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil and natural gas property acquisition activities are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Acquisition costs:
Proved properties	$	4,976	$	341	$	403
Unproved properties	3,968		830		758
Total	$	8,944	$	1,171	$	1,161

Results of Operations from Oil and Natural Gas Producing Activities

Substantially all of the Company’s producing activities are from oil and natural gas activities and are included in the “—Consolidated Statements of Operations.”

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The reserve estimates represent the Company’s net revenue interest in the Company’s properties. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon SEC Prices for the periods ended December 31, 2025, 2024 and 2023, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. All of the Company’s proved reserves included in the reserve reports are located in the continental United States. Although the estimates are believed to be reasonable, actual future production, cash flows, taxes and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

The following table presents changes in estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC:


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2022	79,004	209,964	34,902	148,900
Purchase of reserves in place	10,469	27,011	4,006	18,977
Extensions and discoveries	13,636	34,632	6,150	25,558
Revisions of previous estimates	(5,178)	11,101	3,466	138

Production	(8,028)	(19,130)	(3,108)	(14,324)
As of December 31, 2023	89,903	263,578	45,416	179,249
Purchase of reserves in place	7,891	20,310	3,665	14,941
Extensions and discoveries	13,099	33,498	6,254	24,936
Revisions of previous estimates	(6,472)	4,449	2,837	(2,894)
Divestitures	(919)	(4,605)	(451)	(2,138)
Production	(9,939)	(24,606)	(4,181)	(18,221)
As of December 31, 2024	93,563	292,624	53,540	195,873
Purchase of reserves in place	90,168	336,127	55,102	201,291
Extensions and discoveries	31,305	90,973	15,702	62,170
Revisions of previous estimates	(3,951)	(31,751)	(9,328)	(18,570)
Divestitures	(4)	(12)	(2)	(8)
Production	(17,875)	(51,676)	(8,233)	(34,721)
As of December 31, 2025	193,206	636,285	106,781	406,035

Proved Developed Reserves:
December 31, 2023	69,043	221,462	37,417	143,371
December 31, 2024	76,020	253,271	45,633	163,865
December 31, 2025	147,036	512,302	84,282	316,702

Proved Undeveloped Reserves:
December 31, 2023	20,860	42,116	7,999	35,878
December 31, 2024	17,543	39,353	7,907	32,009
December 31, 2025	46,170	123,983	22,499	89,333

(1)Includes total proved reserves of 219,259 MBOE, 94,019 MBOE, 91,417 MBOE and 81,895 MBOE as of December 31, 2025, 2024, 2023 and 2022, respectively, attributable to a non-controlling interest in the Operating Company.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2025, the Company’s total extensions and discoveries of 62,170 MBOE resulted primarily from the drilling of 1,497 new wells and from 1,071 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 18,570 MBOE were primarily attributable to negative revisions of (i) 11,481 MBOE associated with lower commodity prices, (ii) 4,722 MBOE due to PUD downgrades, and (iii) 2,367 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 201,291 MBOE resulted primarily from the Sitio Acquisition, the 2025 Drop Down, the Morita Ranches Acquisition and other acquisitions of certain mineral and royalty interests.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

During the year ended December 31, 2024, the Company’s total extensions and discoveries of 24,936 MBOE resulted primarily from the drilling of 1,170 new wells and from 447 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 2,894 MBOE were primarily attributable to negative revisions of (i) 6,539 MBOE associated with lower commodity prices, and (ii) 2,936 MBOE due primarily to PUD downgrades partially offset by positive revisions of 6,580 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 14,941 MBOE resulted primarily from the Tumbleweed Acquisitions and other acquisitions of certain mineral and royalty interests. Divestitures of 2,138 MBOE related primarily to non-core mineral and royalty interests.

During the year ended December 31, 2023, the Company’s total extensions and discoveries of 25,558 MBOE resulted primarily from the drilling of 904 new wells and from 179 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 138 MBOE consist of positive revisions of 5,688 MBOE primarily attributable to performance revisions which were largely offset by PUD downgrades of 5,548 MBOE. Total purchases of reserves in place of 18,977 MBOE resulted primarily from the GRP Acquisition and other acquisitions of certain mineral and royalty interests.

Proved Undeveloped Reserves

As of December 31, 2025, the Company’s PUD reserves totaled 46,170 MBbls of oil, 123,983 MMcf of natural gas and 22,499 MBbls of natural gas liquids, for a total of 89,333 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. The Company’s PUD reserves were from 1,653 horizontal wells, 61% of which are operated by Diamondback. Of the horizontal locations, 424 are Wolfcamp A wells, 415 are Wolfcamp B wells, 298 are Middle Spraberry/Jo Mill wells, 257 are Lower Spraberry wells, 82 are Bone Spring wells, 61 are Wolfcamp D wells, 47 are Dean wells, 46 are Barnett wells, 12 are Wolfcamp XY wells, eight are Wolfcamp C wells and three are Upper Spraberry wells.

The following table includes the changes in PUD reserves for 2025:


			MBOE
Beginning proved undeveloped reserves at December 31, 2024			32,009
Undeveloped reserves transferred to developed			(11,848)
Revisions			(5,643)
Purchases			28,395

Extensions and discoveries			46,420
Ending proved undeveloped reserves at December 31, 2025			89,333

The increase in PUD reserves was primarily attributable to positive additions of 46,420 MBOE, primarily from 1,071 new horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate the Company’s acreage position and acquisitions of 28,395 MBOE. These increases in PUD reserves were partially offset by the conversion of 11,848 MBOE of PUD reserves into proved developed reserves and downward revisions of 5,643 MBOE primarily attributable to PUD downgrades of 4,421 MBOE.

All of the Company’s PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2025, none of the Company’s total proved reserves were classified as proved developed non-producing.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on SEC Prices. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future due to development and production of the reserves not occurring in the periods assumed, as well as actual prices realized and actual costs incurred varying significantly from those used in the estimates of proved reserves.

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Viper Energy, Inc.

Notes to Consolidated Financial Statements - (Continued)

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2025, 2024 and 2023:


	December 31,
	2025		2024		2023
	(In millions)
Future cash inflows	$	15,377	$	8,323	$	8,494
Future production taxes	(1,080)		(578)		(594)
Future income tax expense	(1,389)		(749)		(935)
Future net cash flows	12,908		6,996		6,965
10% discount to reflect timing of cash flows	(6,261)		(3,676)		(3,778)
Standardized measure of discounted future net cash flows(1)	$	6,647	$	3,320	$	3,187

(1)Includes a 54%, 48% and 51% non-controlling interest in the Operating Company at December 31, 2025, 2024 and 2023, respectively.

The following table presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:


	December 31,
	2025		2024		2023


Oil (per Bbl)	$	64.80	$	75.61	$	77.93
Natural gas (per Mcf)	$	1.31	$	0.49	$	1.54
Natural gas liquids (per Bbl)	$	18.95	$	20.62	$	23.79

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,320	$	3,187	$	3,454
Purchase of minerals in place	3,738		355		474
Divestiture of reserves	—		(51)		—
Sales of oil and natural gas, net of production costs	(1,252)		(793)		(667)
Extensions and discoveries	1,401		640		627
Net changes in prices and production costs	(279)		(438)		(1,405)
Revisions of previous quantity estimates	(374)		(85)		3
Net changes in income taxes	(370)		70		212
Accretion of discount	368		374		428
Net changes in timing of production and other	95		61		61
Standardized measure of discounted future net cash flows at the end of the period	$	6,647	$	3,320	$	3,187

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2025, our disclosure controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. We are in the process of integrating the entities acquired in the Sitio Acquisition. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2025. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Sitio Acquisition on August 19, 2025. The total assets of Sitio represent approximately 32% of our consolidated total assets as of December 31, 2025, and the operating income of Sitio represent 12% of our total operating income for the year ended December 31, 2025.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Viper Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Viper Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2025, and our report dated February 25, 2026 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of the entities acquired in the Sitio Acquisition, whose financial statements reflect total assets and operating income constituting 32 and 12 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025. As indicated in Management’s Report, the entities acquired in the Sitio Acquisition were acquired during 2025. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of the entities acquired in the Sitio Acquisition.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 25, 2026

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ITEM 9B. OTHER INFORMATION

None of our directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during our fiscal year ended December 31, 2025.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. We have also made the Code of Business Conduct and Ethics available on our website under the “Investors—Corporate Governance” section at https://www.viperenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11. EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a) Documents filed as a part of this Form 10-K
1 and 2. Financial Statements and Financial Statement Schedules

The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules under Part II, Item 8. Financial Statements and Supplementary Data.

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.


3. Exhibits


Exhibit Number						Description
2.1#						Equity Purchase Agreement, dated as of January 30, 2025, by and among Endeavor Energy Resources, LP, as seller, 1979 Royalties LP and 1979 Royalties GP, LLC, as companies, Viper Energy Partners LLC, as buyer, and Viper Energy, Inc., as parent (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-36505) filed on January 30, 2025).
2.2#						Agreement and Plan of Merger, dated as of June 2, 2025, by and among Former Viper, Viper Energy Partners LLC, Sitio Royalties Corp., Sitio Royalties Operating Partnership, LP, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on June 4, 2025).
2.3						Omnibus Transaction Agreement, dated as of December 23, 2025, by and among Viper Energy Partners LLC, Sitio Permian, LP, Sitio Appalachia, LP, Sitio Nuevo, LP, Sitio Anadarko, LP, Moccasin Royalty LLC, Queen Snake Royalty LLC, King Snake Royalty LLC, 1979 Royalties GP, LLC, Mamba Royalty LP, 1979 Royalties, LP, VNOM Merger Sub LP and, with respect to Section 4 only, VNOM Holding Company LLC (incorporated by reference to Exhibit 2.1 of New Viper’s Current Report on Form 8-K (File No. 001-42807) filed on December 30, 2025).
3.1						Amended and Restated Certificate of Incorporation of New Viper (incorporated by reference to Exhibit 3.1 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807), filed on August 19, 2025).
3.2						Certificate of Amendment to the Certificate of Incorporation of New Viper (incorporated by reference to Exhibit 3.2 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807), filed on August 19, 2025).
3.3						Second Amended and Restated Bylaws of New Viper (incorporated by reference to Exhibit 3.3 of New Viper’s Current Report on Form 10-Q (File No. 001-36505), filed on November 5, 2025).
4.1						Description of Capital Stock (incorporated by reference to Exhibit 4.9 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807), filed on August 19, 2025).
4.2						Second Amended and Restated Registration Rights Agreement, dated as of November 10, 2023, effective as of November 13, 2023, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.3 of Former Viper’s Current Report on form 8-K (File No. 001-36505) filed on November 13, 2023).
4.3						Amended and Restated Registration Rights Agreement, dated as of January 30, 2025, by and among Former Viper, Tumbleweed Royalty IV, LLC and the other holders party thereto (incorporated by reference to Exhibit 4.4 of Former Viper’s Registration Statement on Form S-3 (File No. 333-286315) filed on April 1, 2025).
4.4						Registration Rights Agreement, dated as of February 14, 2025, by and among Former Viper and certain affiliates of Morita Ranches Minerals, LLC (incorporated by reference to Exhibit 4.4 of Former Viper’s Annual Report on form 10-K (File No. 001-36505) filed on February 26, 2025).
4.5						Registration Rights Agreement, dated August 19, 2025, between New Viper and certain holders of Sitio Opco Units (incorporated by reference to Exhibit 4.1 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807), filed on August 19, 2025).

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Exhibit Number						Description
4.6						Exchange Agreement, dated as of February 14, 2025, by and among Former Viper, Viper Energy Partners LLC and certain affiliates of Morita Ranches Minerals, LLC (incorporated by reference to Exhibit 4.5 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 26, 2025).
4.7						Class B Common Stock Option Agreement, dated as of October 1, 2024, by and between Former Viper, Viper Energy Partners LLC and Tumbleweed Royalty IV, LLC (incorporated by reference to Exhibit 4.1 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on October 2, 2024).
4.8						Second Amended and Restated Exchange Agreement, dated October 1, 2024, by and among Former Viper, Viper Energy Partners LLC, Diamondback E&P LLC, Diamondback Energy, Inc. and Tumbleweed Royalty IV, LLC (incorporated by reference to Exhibit 4.2 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on October 2, 2024).
4.9						Indenture, dated as of July 23, 2025, between Viper Energy Partners LLC and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on July 23, 2025).
4.10						First Supplemental Indenture, dated as of July 23, 2025, by and among Viper Energy Partners LLC, Former Viper and Computershare Trust Company, National Association, as Trustee (including the form of the Notes) (incorporated by reference to Exhibit 4.2 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on July 23, 2025).
4.11						Second Supplemental Indenture, dated as of August 19, 2025, by and among Viper Energy Partners LLC, New Viper and Computershare Trust Company, National Association (incorporated by reference to Exhibit 4.8 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807), filed on August 19, 2025).
10.1						Amended and Restated Limited Liability Company Agreement of VNOM Holding Company LLC, dated as of December 23, 2025, (incorporated by reference to Exhibit 10.1 of New Viper’s Current Report on Form 8-K (File No. 001-42807), filed on December 30, 2025).
10.2+						Services and Secondment Agreement, dated as of November 2, 2023, by and among Diamondback E&P LLC, Viper Energy Partners LP, Viper Energy Partners GP LLC and Viper Energy Partners LLC (incorporated by reference to Exhibit 10.1 of Former Viper’s Current Report on Form 8-K, (File No. 001-36505) filed on November 2, 2023).
10.3+						Viper Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on November 13, 2023).
10.4+						First Amendment to Amended and Restated 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 22, 2024).
10.5+						Viper Energy, Inc. 2024 Amended and Restated Long-Term Incentive Plan (incorporated by reference to Appendix A of Former Viper’s Schedule DEF 14A (File No. 001-36505) filed on April 25, 2024).
10.6+						Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807) filed on August 19, 2025).
10.7+						Form of Assignment and Assumption Agreement (incorporated by reference to Exhibit 10.3 of New Viper’s Current Report on Form 8-K12B (File No. 001-42807) filed on August 19, 2025).
10.8						Amended and Restated Tax Sharing Agreement, dated as of November 10, 2023, effective as of November 13, 2023, by and between Former Viper and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.2 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on November 13, 2023).
10.9+						2024 Form of Time-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.7 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 22, 2024).
10.10+						2024 Form of Performance-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.8 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 22, 2024).
10.11+						2025 Form of Time-based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.10 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 26, 2025).
10.12+						2025 Form of Performance-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.11 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 26, 2025).
10.13+*#						2026 Form of Time -based Restricted Stock Unit Award Agreement.

Table of Contents


Exhibit Number						Description
10.14+*#						2026 Form of Performance-based Restricted Stock Unit Agreement.
10.15						Credit Agreement, dated as of June 12, 2025, by and among Former Viper, the Borrower, the lenders and guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 of Former Viper’s Current Report on Form 8-K (File No. 001-36505) filed on June 12, 2025).
19.1						General Insider Trading Policy (incorporated by reference to Exhibit 19.1 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 26, 2025).
19.2						Sixth Amended and Restated Supplemental Policy Concerning Trading in Securities of the Company and its Subsidiaries by Certain Designated Persons (incorporated by reference to Exhibit 19.2 of Former Viper’s Annual Report on Form 10-K (File No. 001-36505) filed on February 26, 2025).
21.1*						List of Significant Subsidiaries of Viper Energy Inc.
22.1*						List of Issuers and Subsidiary Guarantors .
23.1*						Consent of Grant Thornton LLP.
23.2*						Consent of Ryder Scott Company, LP.
31.1*						Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*						Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1++						Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
97.1*						Viper Energy, Inc. Clawback Policy .
99.1*						Audit Report of Ryder Scott Company, L.P. dated January 13, 2026, with respect to an audit of the proved reserves, future production and income attributable to certain royalty interests of New Viper as of December 31, 2025.
101						The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2025, formatted in Inline XBRL: (i) Consolidated Statements of Operations, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).


*			Filed herewith.

+			Management contract, compensatory plan or arrangement.
++			The certifications attached as Exhibit 32.1 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#			Schedules (or similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY

None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		VIPER ENERGY, INC.
Date:	February 25, 2026
		By:	VIPER ENERGY, INC.

		By:	/s/ Kaes Van’t Hof
		Name:	Kaes Van’t Hof
		Title:	Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/s/ Kaes Van’t Hof

Chief Executive Officer and Director

February 25, 2026

Kaes Van’t Hof

(Principal Executive Officer)

/s/ Teresa L. Dick

Chief Financial Officer

February 25, 2026

Teresa L. Dick

(Principal Financial and Accounting Officer)

/s/ Steven E. West

Chairman of the Board and Director

February 25, 2026

Steven E. West

/s/ Laurie H. Argo

Director

February 25, 2026

Laurie H. Argo

/s/ Spencer D. Armour III

Director

February 25, 2026

Spencer D. Armour III

/s/ Frank C. Hu

Director

February 25, 2026

Frank C. Hu

/s/ W. Wesley Perry

Director

February 25, 2026

W. Wesley Perry

/s/ James L. Rubin

Director

February 25, 2026

James L. Rubin

/s/ Travis D. Stice

Director

February 25, 2026

Travis D. Stice

Viper Energy - 10-K annual report 2025

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