10-K – 2026-02-25 – fang-20251231.htm

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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 001-35700

Diamondback Energy, Inc.
(Exact name of registrant as specified in its charter)

DE
45-4502447

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

Common Stock, par value $0.01 per share FANG 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 $ 25.8 billion.
As of February 20, 2026, 282,078,989 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of Diamondback 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.

DIAMONDBACK 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
21

Item 1B. Unresolved Staff Comments
39

Item 1C. Cybersecurity
39

Item 3. Legal Proceedings
40

Item 4. Mine Safety Disclosures
40

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
41

Item 6. [R eserved ]
42

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
43

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
59

Item 8. Financial Statements and Supplementary Data
61

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
118

Item 9A. Controls and Procedures
118

Item 9B. Other Information
121

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
121

PART III

Item 10. Directors, Executive Officers and Corporate Governance
121

Item 11. Executive Compensation
121

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
121

Item 13. Certain Relationships and Related Transactions, and Director Independence
121

Item 14. Principal Accountant Fees and Services
121

PART IV

Item 15. Exhibits and Financial Statement Schedules
121

Item 16. Form 10-K Summary
126

Signatures
127

i

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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, which we refer to as this Annual Report or this report:

3-D seismic Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Argus WTI Houston Grade of oil that serves as a benchmark price for oil at Houston, Texas.
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.
Brent A major trading classification of light sweet oil that serves as a benchmark price for oil worldwide.
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.
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.

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 or dry well 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.
Estimated Ultimate Recovery or EUR Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
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 and development costs Capital costs incurred in the acquisition, exploitation and exploration 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 differ 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 acres or gross wells The total acres or wells, as the case may be, in which a working 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.
HSC Hub Natural gas gathering point that serves as a benchmark price for natural gas at the Houston Ship Channel area.

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.

ii

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Net acres or net wells The sum of the fractional working interest owned in gross acres.
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.
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.

iii

Table of Contents

GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this Annual Report:

Adjusted Free Cash Flow
A non-GAAP financial measure calculated as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and further adjusted for the tax impact from divestitures, merger and transaction expenses, costs of early terminations of derivatives and settlements of any treasury locks.

April 2024 Notes The outstanding senior notes issued by Diamondback Energy, Inc. under indentures where Diamondback E&P is the sole guarantor, consisting of the 5.200% Senior Notes due 2027, 5.150% Senior Notes due 2030, 5.400% Senior Notes due 2034, 5.750% Senior Notes due 2054 and 5.900% Senior Notes due 2064.
ASU Accounting Standards Update.
Company Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
Diamondback E&P Diamondback E&P LLC, a Delaware limited liability company and a wholly owned subsidiary of the Company.
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173).
Endeavor Acquisition The acquisition of Endeavor Parent, LLC.

EPA United States Environmental Protection Agency.

Equity Plan The Company’s 2021 Amended and Restated Equity Incentive Plan.
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.

Nasdaq The Nasdaq Global Select Market.
NYMEX New York Mercantile Exchange.
OPEC Organization of the Petroleum Exporting Countries.
OSHA Federal Occupational Safety and Health Act.
Rattler Rattler Midstream LP, a Delaware limited partnership and a wholly owned subsidiary of the Company since 2022.

Rattler LLC Rattler Midstream Operating LLC, a Delaware limited liability company and a wholly owned subsidiary of the Company since 2022.

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.

Tranche A Loans The term loan credit agreement with Diamondback Energy, Inc., as guarantor, with Diamondback E&P, as borrower, and Citibank, N.A., as administrative agent.
Guaranteed Senior Notes The outstanding senior notes issued by Diamondback Energy, Inc. under indentures where Diamondback E&P is the sole guarantor, consisting of the April 2024 Notes, 3.250% Senior Notes due 2026, 3.500% Senior Notes due 2029, 3.125% Senior Notes due 2031, 6.250% Senior Notes due 2033, 5.550% Senior Notes due 2035, 4.400% Senior Notes due 2051, 4.250% Senior Notes due 2052, and 6.250% Senior Notes due 2053.

SOFR The secured overnight financing rate.
TSR Total stockholder return of the Company’s common stock.
Viper (i) New Viper following the Sitio Acquisition, (ii) Former Viper prior to the Sitio Acquisition but after the Viper Conversion, and (iii) Viper Energy Partners LP prior to the Viper Conversion (each term as defined in Note 1—Description of the Business and Basis of Presentation in Item 8. Financial Statements and Supplementary Data of this report).

Viper LLC Prior to December 23, 2025, Viper Energy Partners LLC, a Delaware limited liability company and a 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.

Viper Notes The senior notes issued by Viper Energy, Inc. 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.

Wells Fargo Wells Fargo Bank, National Association.

iv

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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 (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; reserve estimates and our ability to replace or increase reserves; anticipated benefits or other effects of strategic transactions (including the recently completed Double Eagle Acquisition and Viper’s Sitio Acquisition (in each case, as defined below) discussed in this report and other acquisitions or divestitures); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) 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 the Company 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 future performance and our actual outcomes could differ materially from what we have expressed in our forward-looking statements.

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

• geopolitics and market conditions, including changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;
• changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions;
• 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 and instability in the financial sector;
• regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits;
• 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, changing political and social perspectives on climate change and other ESG (as defined below) factors, and risks from our publicly disclosed targets related to sustainability and emissions reduction initiatives;
• challenges in developing our existing leasehold acreage and finding, developing or acquiring additional reserves;
• restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water disposal 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;
• conditions in the capital, financial and credit markets, including the availability and pricing of capital for acquisitions, exploration and development operations;
• challenges with employee retention and an increasingly competitive labor market;
• changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services;
• changes in safety, health, environmental, tax, and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change);
• security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;
v

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• 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 for our oil, natural gas, and natural gas liquids;
• failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas developments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance;
• inability to keep pace with technological developments in our industry;
• failure to meet our obligations under our oil purchase contracts;
• loss of one or more customers or their inability to meet their obligations;
• geographical concentration of our primary operations;
• risks from our return of capital commitment, and uncertainties over our future dividends and share repurchases;
• difficulty in obtaining necessary approvals and permits;
• severe weather conditions and natural disasters;
• changes in the financial strength of counterparties to our credit facilities and hedging contracts;
• our substantial indebtedness and restrictions to our operating and financial flexibility;
• changes in our credit rating;
• failure to identify, complete and successfully integrate acquisitions, including the recently completed Double Eagle Acquisition and Viper’s Sitio Acquisition (each as defined below);
• the Endeavor equityholders’ ability to significantly influence our business and potential conflicts of interest; and
• other risks and factors discussed 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, we operate in a very competitive and rapidly changing environment and 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

Except as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company.” This Annual Report includes certain terms commonly used in the oil and natural gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. We report operations in one reportable segment, the upstream segment.

Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. These formations are characterized by a high concentration of oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

At December 31, 2025, our total acreage position in the Permian Basin was approximately 1,097,846 gross (869,036 net) acres, which consisted primarily of 982,692 gross (774,645 net) acres in the Midland Basin and 115,154 gross (94,391 net) acres in the Delaware Basin.

In addition, our publicly traded subsidiary, Viper, owns mineral interests primarily in the Permian Basin. At December 31, 2025, we owned approximately 42% of Viper’s outstanding shares of common stock on a fully diluted basis, after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report).

As of December 31, 2025, our estimated proved oil and natural gas reserves were 3,617,856 MBOE (which includes estimated reserves of 406,035 MBOE attributable to the mineral interests owned by Viper). As of December 31, 2025, approximately 70% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 1,351 gross (1,244 net) horizontal well locations in which we have a working interest. As of December 31, 2025, our estimated proved reserves were approximately 49% oil, 24% natural gas and 27% natural gas liquids.

Significant Acquisitions and Divestitures

Diamondback Acquisitions and Divestitures

2025 Drop Down

On May 1, 2025, our wholly owned subsidiary Endeavor Energy Resources, LP (“EER LP”) divested all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC (collectively, the “Endeavor Subsidiaries”) to Viper and Viper LLC in exchange for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock (the “2025 Drop Down”).

Double Eagle Acquisition

On April 1, 2025, we completed our acquisition of all of the issued and outstanding interests of DE Permian, LLC, DE IV Combo, LLC and DE IV Operating, LLC, each of which were wholly owned subsidiaries of Double Eagle IV Midco, LLC (the “Double Eagle Acquisition”) for consideration of $3.1 billion in cash and approximately 6.84 million shares of the Company’s common stock, including transaction costs and subject to certain customary post-closing adjustments. The Double Eagle Acquisition consists of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets. We funded the cash portion of the Double Eagle Acquisition through a combination of proceeds from the 2035 Notes (as defined and discussed in Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report), proceeds from the 2025 Term Loan (as defined and discussed in Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report)
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and borrowings under our credit facility.

Non-Core Asset Divestitures

During the year ended December 31, 2025, we divested approximately $1.7 billion in non-core assets, including our 27.5% equity interest in EPIC Crude Holdings, LP (“EPIC”) and our subsidiary, Environmental Disposal Systems, LLC, (“EDS”) which operated water assets acquired in the Endeavor Acquisition as discussed in Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report.

Viper Transactions

Divestiture of Non-Permian Assets

On February 9, 2026, Viper divested all of its 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 “Viper Non-Permian Divestiture”). The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d.

Sitio Acquisition

On August 19, 2025, Viper and Viper LLC completed a series of transactions in which Viper Energy, Inc. (formerly known as New Cobra Pubco, Inc., “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 VNOM Sub, Inc. (formerly known as Viper Energy Inc., “Former Viper”), Viper LLC, 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.

See Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our acquisitions and divestitures during 2025.

Our Business Strategy

Our business strategy includes the following:

• Exercise capital discipline. During 2025, we continued building on our execution track record, generating free cash flow while keeping capital costs under control. Our efficiency gains, particularly in the Midland Basin drilling and completion programs, enabled us to mitigate certain inflationary pressures on variable well costs, which led to a total cash capital expenditure amount of $3.5 billion, consistent with our guidance presented in November 2025. We expect to continue to exercise capital discipline, with a focus on capital efficiency over volume growth and plan to spend between $3.60 billion and $3.90 billion in cash capital expenditures in 2026.

• Focus on low cost development and continuous operational improvement. Our acreage position is generally in contiguous blocks, which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 97% of our acreage, which allows us to efficiently manage our operating costs, pace of development activities and the gathering and marketing of our production. Our average 79% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

• Continue to deliver on our capital return program. We expect to be in a position to continue to deliver on our capital return program, through which we intend to return at least 50% of our quarterly Adjusted Free Cash Flow to our stockholders. Our capital return program is currently focused on a sustainable and growing base dividend and opportunistic stock repurchases. The remainder of our Adjusted Free Cash Flow will be used primarily to reduce debt.

• Leverage our experience operating in the Permian Basin. Our executive team, which has significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by
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optimizing and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other top operators in the area in an effort to benchmark our performance and adopt best practices compared to our peers. The successful execution of the Endeavor Acquisition and the Double Eagle Acquisition have further strengthened our existing operating experience and delivered certain operational synergies ahead of schedule.

• Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. We believe our executive team, with its extensive experience in the Permian Basin, has a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets, as evidenced by the Endeavor and Double Eagle acquisitions.

• Maintain financial flexibility. We seek to maintain a conservative financial position. As of December 31, 2025, Diamondback had $91 million of standalone cash and cash equivalents and our borrowing base was set at $2.5 billion, which was fully available for future borrowings. As of December 31, 2025, Viper had $13 million of cash and cash equivalents, $105 million in outstanding borrowings and approximately $1.4 billion available for future borrowings under its revolving credit facility. Additionally, we have a target of reducing our net debt (which we define as total debt, excluding debt issuance costs, discounts, premiums and unamortized basis adjustments, less cash and cash equivalents) to $10.0 billion. In 2025, we exceeded our previously announced commitment to sell at least $1.5 billion of our non-core assets, and accelerated debt reduction with the proceeds to help maintain a strong balance sheet.

• Deliver on our commitment to environmental, social and governance (“ESG”) performance . We are committed to the safe and responsible development of our resources in the Permian Basin. Our approach to ESG is evidenced through our commitment to people, safety, environmental responsibility, community and sound governance practices.

Our Strengths

We believe the following strengths will help us achieve our business goals:

• Oil rich resource base in one of North America’s leading resource plays. Substantially all of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Permian Basin.

• Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed economic price of approximately $50.00 per Bbl WTI, we currently have approximately 8,854 gross (6,541 net) identified potential horizontal drilling locations on our acreage, based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 10,924 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. The ultimate inter-well spacing at these locations may vary due to different factors, which would result in a higher or lower location count. In addition, we have approximately 17,498 square miles of licensed 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions. We further enhanced our multi-year inventory through the Endeavor Acquisition and the Double Eagle Acquisition.

• Experienced, incentivized and proven management team. Our executive team has a proven track record of executing on large-scale development drilling programs and extensive experience in the Permian Basin. Our executive team has significant experience with both drilling and completing horizontal wells in addition to horizontal well reservoir and geologic expertise.

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• Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating 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 of the Permian Basin is stable and predictable and that we are faced with less operational risks in the Permian Basin when compared to other emerging hydrocarbon basins.

• High degree of operational control. We are the operator of approximately 97% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. We retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks.

Our Properties

Location and Land

The Permian Basin covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. As of December 31, 2025, our total acreage position in the Permian Basin was approximately 1,097,846 gross (869,036 net) acres, which consisted primarily of 982,692 gross (774,645 net) acres in the Midland Basin and 115,154 gross (94,391 net) acres in the Delaware Basin. In addition, as of December 31, 2025, Viper owned mineral interests underlying approximately 1,986,216 gross (36,004 net) royalty acres in the Delaware Basin and approximately 1,891,742 gross (50,595 net) royalty acres in the Midland Basin. Approximately 35% of these net royalty acres are operated by us.

We have been developing multiple pay intervals primarily in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. We believe our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. The following table presents horizontal producing wells in which we have a working interest as of December 31, 2025:

Basin:
Number of Horizontal Wells
Midland 6,105 
Delaware 528 
Other 44 
Total (1)
6,677 

(1) Of these 6,677 total horizontal producing wells, we are the operator of 5,342 wells and have a non-operated working interest in 1,335 additional wells.

Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Strawn, Atoka, Barnett and Woodford formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.

The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.

By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Permian Spraberry, Dean and Wolfcamp formations, which we collectively refer to as the Wolfberry play. Since then, we and most other operators are almost exclusively drilling horizontal wells in the development of unconventional reservoirs in the Permian Basin. As of December 31, 2025, we held working interests in 11,750 gross (9,642 net) producing wells and only royalty interests in 43,912 additional wells.
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Geology

The greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence of the Marathon Uplift and Ancestral Rockies. It is one of the most productive sedimentary basins in the U.S., with established oil and natural gas production from several stacked reservoirs of varying age ranges, most notably Permian aged sediments. In particular, the Permian aged Wolfcamp, Spraberry and Bone Spring Formations have been heavily targeted for several decades. First, through vertical commingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of the Wolfcamp, Spraberry and Bone Spring Formations, the area of the present-day Permian Basin was a continuous sedimentary feature called the Tabosa Basin. During this time, Ordovician, Silurian, Devonian and Mississippian sediments were laid down in a primarily open marine, shelf setting. However, some time frames saw more restrictive settings that led to deposits of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.

The Spraberry and Bone Spring Formations were deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and fine-grained pelagic sediments, which were also deposited in a basinal setting. The best carbonate reservoirs within the Wolfcamp, Spraberry and Bone Spring are generally found in close proximity to the Central Basin Platform, while mudstone reservoirs thicken basin-ward, away from the Central Basin Platform. The mudstone within these reservoirs is organically rich, which when buried to sufficient depth for thermal maturation, became the source of the hydrocarbons found both within the mudstones themselves and in the interbedded conventional clastic and carbonate reservoirs. Due to this complexity, the Wolfcamp, Spraberry and Bone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional and conventional reservoirs.

We have successfully developed several hybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp, Barnett and Woodford formations since we began horizontal drilling in 2012. The mudstones and some clastics exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.

We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas. Our extensive geophysical database currently includes approximately 17,498 square miles of 3-D data. This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resources to be exploited.

Recent and Future Activity

We currently estimate that our cash capital expenditures in 2026 will be between $3.60 billion and $3.90 billion, including $3.05 billion to $3.27 billion for operated horizontal drilling and completions. During the year ended December 31, 2025, we drilled 463 gross (430 net) and completed 503 gross (476 net) operated horizontal wells and incurred capital expenditures for drilling, completing and equipping wells, infrastructure and midstream additions to oil and natural gas properties of $3.5 billion.

We were operating 15 drilling rigs and four completion crews at December 31, 2025 and currently intend to operate between 15 and 18 rigs and approximately five completion crews on average in 2026. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions.

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.
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The purpose of Ryder Scott’s audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates and covered 100% of our total proved reserves for 2025, 2024 and 2023.

Under SEC rules, proved reserves are those quantities of oil and natural gas that, 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 include, but may not be 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. The analogy method was used 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 reserve estimates was considered to be inappropriate. 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 included, but were not limited to, production, 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—Critical Accounting Estimates of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals that have an internal control process to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical staff met with our independent reserve auditor periodically during their January 13, 2026 audit of the December 31, 2025 reserve reports 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 engineers for our properties such as ownership interest, oil and natural gas production, commodity prices and operating and development costs.

The Executive Vice President and Chief Engineer is primarily responsible for overseeing the preparation of all our reserve estimates and overseeing communications with our independent reserve auditor. The 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. 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 materially differ 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 the following:

• review and verification of historical production data, which is based on actual production as reported by us;
• 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;
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• 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 Executive Vice President and Chief Operating Officer;
• prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer, Executive Vice President and Chief Financial Officer, Executive Vice President and Chief Operating Officer, 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 18— Supplemental Information on Oil and Natural Gas Operations (Unaudited) in Item 8. Financial Statements and Supplementary Data of this report.

Potential Drilling Locations

We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $50.00 per Bbl WTI, we currently have approximately 8,854 gross (6,541 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.

The following table presents the number of gross identified economic potential horizontal drilling locations by basin as of December 31, 2025:

Number of Identified Economic Potential Horizontal Drilling Locations
Midland Basin:

Lower Spraberry (1)
1,026
Middle Spraberry (1)
1,453
Wolfcamp A (2)
1,343
Wolfcamp B (2)
1,391
Wolfcamp D (3)
814
Other 1,883
Total Midland Basin 7,910
Delaware Basin:

2nd Bone Springs (3)
325
3rd Bone Springs (3)
254
Wolfcamp A (3)
117
Wolfcamp B (3)
230
Other 18
Total Delaware Basin 944
Total 8,854

(1) Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin and northeast Andrews counties, depending on the prospect area and 880 foot spacing in all other counties.
(2) Our current location count is based on 880 foot spacing.
(3) Our current location count is based on 880 foot to 1,320 foot spacing.

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Oil and Natural Gas Production and Price History

The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids by basin for the fields containing 15% or more, along with other production from fields containing less than 15%, of our total proved reserves:

Midland Basin Delaware Basin Other Total
Production Data:
Year Ended December 31, 2025
Oil (MBbls) 167,183  13,839  440  181,462 
Natural gas (MMcf) 405,840  38,748  3,267  447,855 
Natural gas liquids (MBbls) 74,512  5,395  166  80,073 
Total (MBOE) 309,335  25,692  1,151  336,178 

Year Ended December 31, 2024
Oil (MBbls) 104,875  18,325  125  123,325 
Natural gas (MMcf) 222,574  52,349  757  275,680 
Natural gas liquids (MBbls) 41,559  8,084  57  49,700 
Total (MBOE) 183,530  35,134  308  218,972 

Year Ended December 31, 2023
Oil (MBbls) 75,859  20,246  71  96,176 
Natural gas (MMcf) 140,721  57,129  267  198,117 
Natural gas liquids (MBbls) 25,899  8,296  22  34,217 
Total (MBOE) 125,212  38,064  138  163,413 

The following table sets forth certain price and cost information for each of the periods indicated:

Year Ended December 31,
2025 2024 2023
Average Prices:
Oil ($ per Bbl) $ 64.04  $ 73.52  $ 75.68 
Natural gas ($ per Mcf) $ 0.89  $ 0.32  $ 1.32 
Natural gas liquids ($ per Bbl) $ 17.88  $ 18.99  $ 20.08 
Combined ($ per BOE) $ 40.02  $ 46.12  $ 50.35 

Oil, hedged ($ per Bbl) (1)
$ 63.14  $ 72.68  $ 74.72 
Natural gas, hedged ($ per Mcf) (1)
$ 1.84  $ 0.91  $ 1.48 
Natural gas liquids, hedged ($ per Bbl) (1)
$ 17.88  $ 18.99  $ 20.08 
Average price, hedged ($ per BOE) (1)
$ 40.79  $ 46.38  $ 49.98 

Average Costs ($/BOE):
Lease operating expenses $ 5.55  $ 5.87  $ 5.34 
Production and ad valorem taxes 2.53  2.91  3.21 
Gathering, processing and transportation expense 1.53  1.63  1.76 
General and administrative - cash component 0.62  0.68  0.59 
Total operating expense - cash $ 10.23  $ 11.09  $ 10.90 

General and administrative - non-cash component $ 0.24  $ 0.30  $ 0.33 
Depreciation, depletion, amortization and accretion $ 14.99  $ 13.02  $ 10.68 
Interest expense, net $ 0.73  $ 0.62  $ 0.97 

Production Costs (2)
$ 7.08  $ 7.50  $ 7.10 

(1) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
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(2) Average production costs is comprised of lease operating expenses and gathering, processing and transportation expense.

Wells Drilled and Completed in 2025

The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2025:

Drilled Completed
Area: Gross Net Gross Net
Midland Basin 459  426  488  463 
Delaware Basin 4  4  15  13 

Total 463  430  503  476 

As of December 31, 2025, we operated the following wells in the Permian Basin:

Vertical Wells Horizontal Wells Total
Area: Gross Net Gross Net Gross Net
Midland Basin 4,447  4,229  4,868  4,560  9,315  8,789 
Delaware Basin 40  35  474  441  514  476 

Total 4,487  4,264  5,342  5,001  9,829  9,265 

Productive Wells

As of December 31, 2025, we owned an interest in a total of 55,662 gross productive wells with an average unweighted 82% working interest in 11,750 gross (9,642 net) wells and an average 2.0% royalty interest in 43,912 additional wells. Through our subsidiary, Viper, we own an average 2.2% net revenue interest in 43,355 of the total 55,662 gross productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells 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 and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information regarding productive wells by basin as of December 31, 2025:

Gross Wells Net Wells
Oil Natural Gas Total Oil Natural Gas Total
Midland Basin 30,114  239  30,353  9,007  68  9,075 
Delaware Basin 9,390  3,220  12,610  462  19  481 
Denver-Julesburg Basin 6,140  232  6,372  —  —  — 

Other 5,400  927  6,327  27  59  86 
Total productive wells 51,044  4,618  55,662  9,496  146  9,642 

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Drilling Results

The following tables set forth information with respect to the number of wells drilled during the periods indicated by basin. Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

Year Ended December 31, 2025
Midland Basin Delaware Basin Total
Gross Net Gross Net Gross Net
Development:
Productive 444  412  4  4  448  416 
Dry —  —  —  —  —  — 
Exploratory:
Productive 15  14  —  —  15  14 
Dry —  —  —  —  —  — 
Total:
Productive 459  426  4  4  463  430 
Dry —  —  —  —  —  — 

Year Ended December 31, 2024
Midland Basin Delaware Basin Total
Gross Net Gross Net Gross Net
Development:
Productive 322  308  30  26  352  334 
Dry —  —  —  —  —  — 
Exploratory:
Productive 20  17  —  —  20  17 
Dry —  —  —  —  —  — 
Total:
Productive 342  325  30  26  372  351 
Dry —  —  —  —  —  — 

Year Ended December 31, 2023
Midland Basin Delaware Basin Total
Gross Net Gross Net Gross Net
Development:
Productive 192  179  29  25  221  204 
Dry —  —  —  —  —  — 
Exploratory:
Productive 123  106  6  5  129  111 
Dry —  —  —  —  —  — 
Total:
Productive 315  285  35  30  350  315 
Dry —  —  —  —  —  — 

As of December 31, 2025, we had 22 gross (21 net) operated wells in the process of drilling and 312 gross (290 net) wells in the process of completion or waiting on completion.

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Acreage

The following table sets forth information as of December 31, 2025 relating to our leasehold acreage in the Permian Basin:

Developed Acreage (1)
Undeveloped Acreage Total Acreage (2)

Basin: Gross Net Gross Net Gross Net
Midland 506,360  402,952  476,332  371,693  982,692  774,645 
Delaware 69,220  57,800  45,934  36,591  115,154  94,391 

Total 575,580  460,752  522,266  408,284  1,097,846  869,036 

(1) Does not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.
(2) Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.

Undeveloped Acreage Expirations

As of December 31, 2025, the following gross and net undeveloped acres are set to expire over the next five years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.

Acres Expiring
Midland Delaware Total
Gross Net Gross Net Gross Net
2026 13,364  10,579  408  323  13,772  10,902 
2027 28,991  22,949  —  —  28,991  22,949 
2028 33,121  26,218  —  —  33,121  26,218 
2029 780  617  —  —  780  617 
2030 2,935  2,323  —  —  2,935  2,323 

Total 79,191  62,686  408  323  79,599  63,009 

Title to Properties

Prior to the drilling of an oil or natural gas well, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. To the extent title opinions or other investigations reflect title defects impacting the development or operation of a producing property, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, an updated title review, or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Marketing and Customers

We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the years ended December 31, 2025, 2024 and 2023 four purchasers each accounted for more than 10% of our revenue. We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For additional information regarding our customer concentrations, see Note 3— Revenue from Contracts with Customers in Item 8. Financial Statements and Supplementary Data of this report.

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Delivery Commitments

Certain of our firm sales agreements include delivery commitments that specify the delivery of a fixed and determinable quantity of oil. We expect our production and reserves will continue to be the primary means of fulfilling our future commitments. However, these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment. In 2023, we began purchasing third-party volumes to fulfill certain delivery commitments. For additional information regarding commitments, see Note 15— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.

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 not only explore for and produce oil and natural gas, but also 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 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. 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. 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.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 15% to 35%, resulting in a net revenue interest to us generally ranging from 65% to 85%.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas buyers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In our exploration and production business, seasonal weather conditions, and lease stipulations can limit our 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 meeting our 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

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements. 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 our cost of doing business and, consequently, affects our profitability.

Environmental Matters. Our 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 our operations or related to our owned or operated facilities. 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
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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 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 operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 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. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, 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 us 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
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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 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. We believe we are in material compliance with the requirements of each of these laws.

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. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 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
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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, 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
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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 OSHA for 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 use of produced water, a moratorium on new produced water disposal wells, and additional monitoring and reporting requirements could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling and completion activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

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, state or local 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 we operate, our operations or any work performed related to them could be prohibited or delayed, or expensive mitigation could be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA.
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However, the designation of previously unprotected species as threatened or endangered in areas where we operate could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.

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 our cost of doing business and, consequently, affects our profitability, 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.

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. Our operations 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 we can produce from our wells or limit the number of wells or the locations at which we 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 you 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 in areas where we operate. 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 of the natural gas we produce and the manner in which we market our production. 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,” which include all of our sales of our own production. 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,
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including the ability to assess substantial civil penalties for violations. We are subject to that FERC authority and related policies.

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.

Our 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. We are subject to such regulation when we provide such interstate transportation of oil in our midstream operations, and we have a tariff on file with FERC for that purpose. 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.

Further, interstate and intrastate common carrier oil pipelines, including ours and those on which we transport oil, 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 us to the same extent as to our competitors.

Safety and Maintenance Regulation. In our midstream operations, we are subject to regulation by the U.S. Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including natural gas liquids and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

We are also subject to the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The PHMSA regulations also provide for the inspection and testing of pipelines and the correction of anomalies, and require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans and spill response training for pipeline personnel.

The Pipeline Safety and Job Creation Act, enacted in 2011, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020, also known as the PIPES Act, amended the HLPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $272,926 and $2,729,245, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures, and, on August 24, 2022, PHMSA published a final rule strengthening integrity management requirements for onshore gas
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transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events. In October 2024, PHMSA issued a notice of proposed rulemaking recommending modernizing and simplifying the hazardous material regulations, enhancing safety standards across rail, highway, and vessel transportation while also providing annual cost savings for businesses and consumers. Following the change in Presidential Administration, PHMSA in January 2025 extended the public comment period for the rulemaking until April 28, 2025, but has not otherwise acted on that proposed rulemaking. In May 2025, PHMSA issued two Advance Notices of Proposed Rulemaking (“ANPRM”) seeking public comment on updates to its safety regulations for pipelines and LNG facilities aimed at implementing the President’s “Unleashing American Energy” Executive Order. In June 2025, PHMSA issued another ANPRM to solicit stakeholder feedback on whether to repeal or amend any requirements in its pipeline safety regulations to eliminate undue burdens on the identification, development, and use of domestic energy resources and to improve government efficiency.

The ultimate impact of those efforts of the Trump Administration remains to be seen. If safety standards were to become more stringent in the future, it could cause us, like other similarly situated pipeline operators, to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated or expanded basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders for any violations could have an adverse impact on our business, financial condition, results of operation and cash flow.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have been certified by PHMSA to assume responsibility to enforce the federal standards. For example, on December 17, 2019, the Texas Railroad Commission adopted rules requiring that operators of gathering lines take “appropriate” actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with applicable pipeline safety and pollution control requirements.