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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
or

☐ 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)

DE
39-2596878

State or other jurisdiction of incorporation or organization
(I.R.S. Employer Identification No.)

500 West Texas Ave.,

Suite 100
Midland, TX 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

i

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 com modity 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.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate
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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.