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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31 , 2025
☐      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File No.  001-13726

EXPAND ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Oklahoma
73-1395733

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
6100 North Western Avenue,
Oklahoma City,
Oklahoma
73118

(Address of principal executive offices) (Zip Code)
(405)
  848-8000

(Registrant’s telephone number, including area code)

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, $0.01 par value per share EXE The Nasdaq Stock Market LLC
Class A Warrants to purchase Common Stock EXEEW The Nasdaq Stock Market LLC
Class B Warrants to purchase Common Stock EXEEZ The Nasdaq Stock Market LLC
Class C Warrants to purchase Common Stock EXEEL The Nasdaq Stock Market LLC

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  ☒  
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No  ☐
The aggregate market value of our common stock held by non-affiliates on June 30, 2025 was approximately $ 19.6 billion. As of February 11, 2026, there were 240,398,260 shares of our common stock outstanding.
__________________________________________
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2026 Annual Meeting of Stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K.

EXPAND ENERGY CORPORATION AND SUBSIDIARIES
FORM 10-K
TABLE OF CONTENTS

PART I
Page

Item 1.
Business
12

Item 1A.
Risk Factors
28

Item 1B.
Unresolved Staff Comments
50

Item 1C.
Cybersecurity
50

Item 2.
Properties
51

Item 3.
Legal Proceedings
52

Item 4.
Mine Safety Disclosures
52

PART II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
53

Item 6.
Reserved
53

Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
54

Liquidity and Capital Resources
57

Results of Operations
62

Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
69

Item 8 .
Financial Statements and Supplementary Data
70

Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
119

Item 9A.
Controls and Procedures
119

Item 9B.
Other Information
120

Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
120

PART III

Item 10.
Directors, Executive Officers and Corporate Governance
120

Item 11.
Executive Compensation
120

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
120

Item 13.
Certain Relationships and Related Transactions, and Director Independence
120

Item 14.
Principal Accountant Fees and Services
120

PART IV

Item 15.
Exhibits and Financial Statement Schedules
121

Item 16.
Form 10-K Summary
125

Signatures
126

3

Explanatory Note and Definitions

On October 1, 2024, Chesapeake Energy Corporation completed its previously announced merger with Southwestern Energy Company. In connection with the Southwestern Merger, Chesapeake Energy Corporation changed its name to Expand Energy Corporation.
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Expand Energy,” the “Company” and “Registrant” refer to Expand Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. The following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K (this “Form 10-K” or this “report”):
“2025 Credit Facility” means the amended and restated credit facility entered into on September 30, 2025.
“Adjusted Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures and contributions to investments, adjusted to exclude certain items management believes affect the comparability of operating results.
“ASC” means Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“Bankruptcy Code” means Title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.
“Bbl” or “Bbls” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” means billion cubic feet.
“Bcfe” means billion cubic feet of natural gas equivalent.
“BLM” means the Bureau of Land Management.
“Chapter 11 Cases” refers to the voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code filed in the Bankruptcy Court by the Debtors.
“Chesapeake” means Chesapeake Energy Corporation, prior to the Southwestern Merger.
“Class A Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan, the Class B Warrants, and the Class C Warrants), at an initial exercise price per share of $27.63. The Class A Warrants were exercisable from the Effective Date until February 9, 2026.
“Class B Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan and the Class C Warrants), at an initial exercise price per share of $32.13. The Class B Warrants were exercisable from the Effective Date until February 9, 2026.
“Class C Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan), at an initial exercise price per share of $36.18. The Class C Warrants were exercisable from the Effective Date until February 9, 2026.
“Completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
“Confirmation Order” means the order confirming the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, Docket No. 2915, entered by the Bankruptcy Court on January 16, 2021.
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“Credit Agreement” means the Amended and Restated Credit Agreement, dated as of September 30, 2025, which provides for the 2025 Credit Facility with the lenders and issuing banks party thereto from time to time, and JPMorgan Chase Bank, N.A., as administrative agent.
“DD&A” means depreciation, depletion and amortization.
“Debtors” means Chesapeake Energy Corporation prior to the Southwestern Merger, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
“Developed Acreage” means acres which are allocated or assignable to producing wells or wells capable of production.
“Dry Well” means a well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
“Effective Date” means February 9, 2021.
“ESG” means environmental, social and governance.
“Exploratory Well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.
“FASB” means the Financial Accounting Standards Board.
“Formation” means a succession of sedimentary beds that were deposited under the same general geologic conditions.
“Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Unsecured Claim” means any Claim against any Debtor that is not otherwise paid in full during the Chapter 11 Cases pursuant to an order of the Bankruptcy Court and is not an Administrative Claim, a Priority Tax Claim, an Other Priority Claim, an Other Secured Claim, a Revolving Credit Facility Claim, a FLLO Term Loan Facility Claim, a Second Lien Notes Claim, an Unsecured Notes Claim, an Intercompany Claim, or a Section 510(b) Claim.
“Gross Acres or Gross Wells” means the total acres or wells, as the case may be, in which a working interest is owned.
“LNG” means liquefied natural gas.
“LTIP” means the Expand Energy Corporation 2021 Long Term Incentive Plan.
“MBbls” means one thousand barrels of oil or other liquid hydrocarbons.
“MMBbls” means one million barrels of oil or other liquid hydrocarbons.
“Mcf” means thousand cubic feet.
“Mcfe” means one thousand cubic feet of natural gas equivalent, with one barrel of oil or NGL converted to an equivalent volume of natural gas using the ratio of one barrel of oil or NGL to six Mcf of natural gas.
“MMcf” means million cubic feet.
“MMcfe” means million cubic feet of natural gas equivalent.
“Net Acres or Net Wells” means the sum of the fractional working interests owned in gross acres or gross wells.
“NGL” means natural gas liquids.
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“NYMEX” means New York Mercantile Exchange.
“OPEC+” means the Organization of the Petroleum Exporting Countries Plus.
“Petition Date” means June 28, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
“Plan” means the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
“Play” means a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas, oil and NGL reserves.
“Present Value of Estimated Future Net Revenues” or “PV-10” (non-GAAP) means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
“Price Differential” means the difference in the price of natural gas, oil or NGL received at the sales point and the NYMEX price.
“Prior Credit Facility” means the reserve-based credit facility entered into on December 9, 2022.
“Productive Well” means a well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“Proved Properties” means properties with proved reserves.
“Proved Reserves” has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
“Proved Undeveloped Reserves (PUDs)” means 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. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Rights Offering” means the common stock rights offering for the Rights Offering Amount consummated by the Debtors on the Effective Date.
“SEC” means United States Securities and Exchange Commission.
“SOFR” means a rate equal to the secured overnight financing rate as administered by the SOFR Administrator, the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).
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“Southwestern” means Southwestern Energy Company.
“Southwestern Merger” means Chesapeake’s merger with Southwestern, which closed on October 1, 2024.
“Standardized Measure” means the discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
“Tcf” means trillion cubic feet.
“Tcfe” means trillion cubic feet of natural gas equivalent.
“Undeveloped Acreage” means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether the acreage contains proved reserves.
“Unproved Properties” means properties with no proved reserves.
“Vine” means Vine Energy Inc.
“Warrants” means, collectively, the Class A Warrants, Class B Warrants and Class C Warrants.
“Working Interest” means the operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/Mcf” means per Mcf.
“/Mcfe” means per Mcfe.
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Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to armed conflict between Russia and Ukraine, instability in the Middle East and Venezuela and changes in China-Taiwan relations, along with the effects of the current global economic environment, and the impact of each on our business, financial condition, results of operations and cash flows, actions by, or disputes among or between, members of OPEC+ and other foreign oil-exporting countries, market factors, market prices, our ability to meet debt service requirements, our ability to continue to pay cash dividends, the amount and timing of any cash dividends and our sustainability initiatives. Forward-looking and other statements in this Form 10-K regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as “aim,” “predict,” “should,” "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
• Reduced demand for natural gas, oil and natural gas liquids;
• negative public perceptions of our industry;
• competition in the natural gas and oil exploration and production industry;
• the volatility of natural gas, oil and NGL prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;
• risks from regional epidemics or pandemics and related economic turmoil, including supply chain constraints;
• write-downs of our natural gas and oil asset carrying values due to low commodity prices;
• significant capital expenditures are required to replace our reserves and conduct our business;
• our ability to replace reserves and sustain production;
• uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
• drilling and operating risks and resulting liabilities;
• our ability to generate profits or achieve targeted results in drilling and well operations;
• leasehold terms expiring before production can be established;
• risks from our commodity price risk management activities;
• uncertainties, risks and costs associated with natural gas and oil operations;
• our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;
• pipeline and gathering system capacity constraints and transportation interruptions;
• risks related to our plans to participate in the global LNG value chain;
• terrorist activities and/or cyber-attacks adversely impacting our operations;
• risks from failure to protect personal information and data and compliance with data privacy and security laws and regulations;
• disruption of our business by natural or human causes beyond our control;
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• a deterioration in general economic, business or industry conditions;
• the impact of inflation and commodity price volatility, including as a result of decisions made by OPEC+ and armed conflict between Russia and Ukraine, instability in the Middle East and Venezuela, and changes in China-Taiwan relations, along with the effects of the current global economic environment, on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and on U.S. and global financial markets;
• our inability to access the capital markets on favorable terms;
• the limitations on our financial flexibility due to our level of indebtedness and restrictive covenants from our indebtedness;
• challenges with employee recruitment and retention and an increasingly competitive labor market;
• risks related to acquisitions or dispositions, or potential acquisitions or dispositions;
• 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;
• our ability to achieve and maintain sustainability certifications, goals and commitments;
• environmental and sustainability legislation and regulatory initiatives, including those addressing the impact of climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;
• federal and state tax proposals affecting our industry;
• risks related to an annual limitation on the utilization of our tax attributes, which was triggered upon the completion of the Southwestern Merger, as well as trading in our common stock, additional issuance of common stock, and certain other stock transactions, which could lead to an additional, potentially more restrictive, annual limitation; and
• other factors that are described under Risk Factors in Item 1A of Part I of this Form 10-K.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates which may differ from the actual quantities of natural gas, oil and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.
We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation and have no intention to update this information, except as required by law. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
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Summary Risk Factors

The following is a summary description of material risks and uncertainties facing our Company.

Risks Related to Operating our Business

• Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
• Conservation measures and technological advances could reduce demand for natural gas and oil.
• Negative public perception regarding us or our industry could have an adverse effect on our operations.
• The gas and oil exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
• Risks related to potential acquisitions or dispositions may adversely affect our business.
• Government policies and support and market demand for low-carbon technologies.
• If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write-downs of the carrying value of our natural gas and oil properties.
• Significant capital expenditures are required to replace our reserves and conduct our business.
• If we are not able to replace reserves, we may not be able to sustain production.
• The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
• Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
• Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
• Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
• Natural gas and oil operations are uncertain and involve substantial costs and risks.
• Our ability to produce natural gas, oil and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in compliance with environmental laws.
• Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
• Our business strategy includes participating in the global LNG value chain, which is dependent, in part, on the growing U.S. LNG export market, a highly regulated and capital-intensive industry with a number of inherent commercial and regulatory risks. U.S. LNG exports have helped drive domestic demand for natural gas, and, as a natural gas producer, we could be materially and adversely impacted by a deterioration in the U.S. LNG export industry, which could in turn reduce demand for natural gas. In addition, we may seek to more directly participate in the LNG value chain through direct marketing arrangements with LNG export facilities and/or end users, which could expose us to additional commercial risks associated with the global LNG markets.
• The departure of key management personnel and the failure to attract and retain talent could adversely affect our operations.
• Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.
• We collect, process, store and use personal information and other data, and our actual or perceived failure to protect such information and data or comply with data privacy and security laws and regulations could damage our reputation and brand and harm our business and operating results.
• A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
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• Regional epidemics or pandemics and related economic turmoil, including supply chain constraints, have affected, and could in the future adversely affect our business, financial condition, results of operations and cash flows.

Financial Risks Related to our Business

• We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
• Restrictive covenants in certain of our existing and future debt instruments may limit our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Legal and Regulatory Risks

• We are subject to extensive governmental regulation, which can change and could adversely impact our business.
• Costs to comply with environmental, health and safety regulations and initiatives can be significant.
• Increasing attention to sustainability matters and our ability to achieve and maintain sustainability certifications, goals and commitments may impact our business, financial results or stock price.
• The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
• The completion of the Southwestern Merger in 2024 triggered an annual limitation on the utilization of our tax attributes, reducing our ability to offset future taxable income, which may result in an increase to income tax liabilities. In addition, trading in our common stock, additional issuance of common stock, and certain other stock transactions could lead to an additional, potentially more restrictive, annual limitation.

See Risk Factors included in Item 1 A. of Part 1 of this report for further discussion of these risks.
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PART I

ITEM 1. Business

Unless the context otherwise requires, references to “Expand Energy,” the “Company,” “us,” “we,” “our” and “ours” in this report are to Expand Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.

Our Business

Expand Energy is the largest independent natural gas producer in the U.S., based on net daily production, and is focused on responsibly developing an abundant supply of natural gas, oil and NGL to expand energy access for all. Our operations are located in Louisiana and Texas in the Haynesville and Bossier Shales (“Haynesville”), in Pennsylvania in the Marcellus Shale (“Northeast Appalachia”) and in West Virginia and Ohio in the Marcellus and Utica Shales (“Southwest Appalachia”) and include working interests in approximately 6,600 gross natural gas and oil wells.
On October 1, 2024, we completed the Southwestern Merger, creating a premier energy company that we believe is underpinned by a leading natural gas portfolio adjacent to the highest demand markets, premium inventory, a resilient financial foundation and an investment grade balance sheet. We believe that we are uniquely positioned to deliver affordable, lower-carbon energy to meet growing domestic and international demand while creating sustainable value for stakeholders. Since completing our merger with Southwestern, we’ve continued to focus on strengthening our balance sheet by reducing total debt by approximately $1.2 billion and upsized our 2025 Credit Facility capacity to $3.5 billion. In 2025, we joined the S&P 500 index and returned approximately $865 million to shareholders through dividends and share repurchases.

Information About Us

We make available, free of charge on our website at expandenergy.com , our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Expand Energy, that file electronically with the SEC.

Business Strategy

Our strategy is to create resilient shareholder value through the responsible development of our significant resource plays while continuing to be a leading provider of natural gas to growing markets. We continue to focus on improving margins through operating efficiencies, marketing and commercial efforts and financial discipline and improving our safety and sustainability performance. To accomplish these goals, we plan to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to invest in projects designed to reduce the environmental impact of our production activities.
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Operating Areas

We focus our acquisition, exploration, development and production efforts in the geographic operating areas described below.
Haynesville - Haynesville and Bossier Shales in Louisiana and Texas.
Northeast Appalachia - Marcellus Shale in Pennsylvania.
Southwest Appalachia - Marcellus and Utica Shales in Ohio and West Virginia.

Well Data

As of December 31, 2025, we held a working interest in approximately 6,600 (4,600 net) wells of which substantially all were classified as productive natural gas wells. During 2025, we operated 5,800 gross wells and held a non-operating working interest in 800 gross wells. We also completed 272 gross (202 net) wells as operator and participated in another 39 gross (1 net) well completed by other operators. We operate approximately 99% of our current daily production volumes. Additionally, we held an overriding or royalty interest in approximately 3,300 wells without a held working interest.

Drilling Activity

The following table sets forth the wells we completed or participated in during the periods indicated. During the years ended December 31, 2025, 2024 and 2023, we did not complete any productive or dry exploratory wells. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:

2025 2024 2023
Gross % Net % Gross % Net % Gross % Net %
Development:
Productive 311  100  203  100  87  100  62  100  194  100  109  100 
Dry —  —  —  —  —  —  —  —  —  —  —  — 
Total 311  100  203  100  87  100  62  100  194  100  109  100 

The following table shows the wells we completed or participated in by operating area:

2025 2024 2023
Gross Wells Net Wells Gross Wells Net Wells Gross Wells Net Wells
Haynesville 139  105  48  41  84  51 
Northeast Appalachia 112  59  38  20  78  37 
Southwest Appalachia 60  39  1  1  —  — 
Eagle Ford —  —  —  —  32  21 
Total 311  203  87  62  194  109 

As of December 31, 2025, we had 115 gross (88 net) wells in the process of being drilled or completed.
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Production Volumes, Sales Prices, Production Expenses and Gathering, Processing and Transportation Expenses

The following tables present information regarding our net production volumes, average sales price received for our production, and production and gathering, processing and transportation expenses per Mcfe for the periods indicated for our significant fields:

Production
Natural Gas (Bcf) Oil (MMBbl) NGL (MMBbl) Total (Bcfe)
2025
Haynesville 1,095 —  —  1,095
Northeast Appalachia 958 —  —  958
Southwest Appalachia 356 5.9 29.6 569

Total Production 2,409 5.9 29.6 2,622
2024
Haynesville 561 —  —  561
Northeast Appalachia 662 —  —  662
Southwest Appalachia 98  1.2 7.8 152 

Total Production 1,321 1.2 7.8 1,375
2023
Haynesville 566 —  —  566
Northeast Appalachia 669 —  —  669

Eagle Ford 31 7.7 3.8 100
Total Production 1,266  7.7 3.8 1,335

Average Sales Price of Production (a)
Expenses ($/Mcfe)
Natural Gas ($/Mcf) Oil ($/Bbl) NGL ($/Bbl) Total ($/Mcfe) Production GP&T
2025
Haynesville $ 3.17  $ —  $ —  $ 3.17  $ 0.27  $ 0.73 
Northeast Appalachia $ 2.99  $ —  $ —  $ 2.99  $ 0.17  $ 0.87 
Southwest Appalachia $ 3.08  $ 54.47  $ 24.48  $ 3.76  $ 0.31  $ 1.30 

Total $ 3.08  $ 54.47  $ 24.48  $ 3.23  $ 0.24  $ 0.91 
2024
Haynesville $ 2.14  $ —  $ —  $ 2.14  $ 0.30  $ 0.58 
Northeast Appalachia $ 1.88  $ —  $ —  $ 1.88  $ 0.15  $ 0.77 
Southwest Appalachia $ 2.42  $ 60.41  $ 27.44  $ 3.42  $ 0.32  $ 1.33 

Total $ 2.03  $ 60.41  $ 27.44  $ 2.16  $ 0.23  $ 0.75 
2023
Haynesville $ 2.30  $ —  $ —  $ 2.30  $ 0.33  $ 0.46 
Northeast Appalachia $ 2.22  $ —  $ —  $ 2.22  $ 0.12  $ 0.65 

Eagle Ford $ 2.25  $ 77.80  $ 25.62  $ 7.64  $ 0.91  $ 1.57 
Total $ 2.25  $ 77.80  $ 25.62  $ 2.66  $ 0.27  $ 0.64 
___________________________________________
(a) Excludes the effect of hedging.
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Natural Gas, Oil and NGL Reserves

The tables below set forth information as of December 31, 2025, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue and the standardized measure of discounted future net cash flows. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated natural gas, oil and NGL reserves we own. All of our estimated reserves are located within the United States.

December 31, 2025
Natural Gas Oil NGL Total
(Bcf) (MMBbl) (MMBbl) (Bcfe)
Proved developed 16,395  35.0  328.5  18,576 
Proved undeveloped 6,180  23.8  163.4  7,304 
Total proved (a)
22,575  58.8  491.9  25,880 

Proved
Developed
Proved
Undeveloped
Total
Proved

Standardized measure (b)
$ 17,126 
Estimated future net revenue (b)
$ 27,453  $ 9,549  $ 37,002 
Present value of estimated future net revenue (PV-10) (b)
$ 15,047  $ 4,327  $ 19,374 

___________________________________________
(a)    Haynesville, Northeast Appalachia and Southwest Appalachia accounted for approximately 23%, 42% and 35%, respectively, of our estimated proved reserves by volume as of December 31, 2025.
(b)    Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2025, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025. The price used in our PV-10 measure was $3.39 per Mcf of natural gas and $65.34 per Bbl of oil and NGL, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2025. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $2.2 billion as of December 31, 2025.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10, a non-GAAP measure, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved natural gas and oil reserves.
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As of December 31, 2025, our proved reserve estimates included 7,304 Bcfe of reserves classified as proved undeveloped, compared to 3,842 Bcfe as of December 31, 2024. Presented below is a summary of changes in our proved undeveloped reserves for 2025:

Total
(Bcfe)
Proved undeveloped reserves, beginning of period 3,842 
Extensions and discoveries 49 
Revisions of previous estimates 4,998 
Conversion to proved developed reserves (1,585)
Purchase of reserves-in-place — 
Sales of reserves-in-place — 
Proved undeveloped reserves, end of period 7,304 

As of December 31, 2025, all PUDs were planned to be developed within five years of original recording. In 2025, we invested approximately $658 million to convert 1,585 Bcfe of PUDs to proved developed reserves. We added 49 Bcfe of PUD reserves through extensions and discoveries due to new PUDs added in Southwest Appalachia. We had a net upward revision in previous estimates of 4,998 Bcfe. The net upward revision primarily consisted of 5,430 Bcfe of upward revisions due to new PUDs that had improved economics and were in areas previously classified as proved. These upward revisions were partially offset by negative revisions due to development plan changes of 146 Bcfe, and by production forecast and commercial terms updates on existing PUD locations of 286 Bcfe.
The future net revenue attributable to our estimated PUDs was $9.5 billion, and the present value was $4.3 billion as of December 31, 2025. These values were calculated assuming that we will expend approximately $4.2 billion to develop these reserves ($2,044 million in 2026, $1,379 million in 2027, $700 million in 2028, $27 million in 2029 and $13 million in 2030). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as commodity prices, unexpected developmental drilling results, title issues and infrastructure availability or constraints.
As of December 31, 2025, approximately 648 Bcfe, or 3%, of our total proved reserves were developed and non-producing.
Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2025, 2024 and 2023, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. Accordingly, reserve estimates often differ from the actual quantities of natural gas, oil and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Natural Gas,
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Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.
Reserves Estimation
We engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to audit our total proved reserves as of December 31, 2025. A copy of the audit letter issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical persons at the firm primarily responsible for overseeing the audit of our reserve estimates are set forth below.
• Over 45 combined years of practical experience in the estimation and evaluation of reserves;
• Licensed Professional Engineer in the State of Texas and Bachelor of Science degree in Chemical Engineering;
• Licensed Professional Geoscientist in the State of Texas and Bachelor of Science and Master of Science degrees in Geology.
Our Corporate Reserves Department prepared our estimated proved reserves as of December 31, 2025 disclosed in this report. Those estimates were established utilizing standard geological and engineering technologies, which are generally accepted by the petroleum industry and were based upon the best available production, engineering and geologic data. These technologies, including computational methods, provide reasonable certainty in our reserves estimation and include technologies and inputs such as drilling results and well performance, decline curve analysis of wells in analogous reservoirs, material balance, volumetric calculation, statistical analysis, well logs, geologic maps and seismic data.
Our Manager – Corporate Reserves, who is in charge of our Corporate Reserves Department, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. His qualifications include the following:
• Over 18 years of practical experience in the oil and gas industry, with over 16 years in reservoir engineering;
• Licensed Professional Engineer (Petroleum) in the State of Oklahoma;
• Member in good standing of the Society of Petroleum Evaluation Engineers;
• Bachelor of Science in Mechanical Engineering; and
• Masters of Business Administration.
We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserve estimates. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.
We maintain internal controls such as the following to ensure the reliability of reserves estimations:
• We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by the Manager – Corporate Reserves.
• The Corporate Reserves Department reviews our proved reserves at the close of each quarter.
• Each quarter, Reservoir Managers, the Manager – Corporate Reserves, the Vice Presidents of each operating area and the Vice President of Corporate and Strategic Planning review all significant reserves changes and all new proved undeveloped reserves additions.    
• The Corporate Reserves Department reports independently of our operations.
• The five-year PUD development plan is reviewed and approved annually by the Manager – Corporate Reserves and the Vice President of Corporate and Strategic Planning.
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Acreage

The following table sets forth our gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage as of December 31, 2025. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest.

Developed Leasehold Undeveloped Leasehold Total
Gross Acres Net Acres Gross Acres Net Acres Gross Acres Net Acres
(in thousands)
Haynesville 628  561  292  184  920  745 
Northeast Appalachia 746  497  234  207  980  704 
Southwest Appalachia 294  243  439  349  733  592 
Other (a)
300  283  1,295  1,217  1,595  1,500 
Total 1,968  1,584  2,260  1,957  4,228  3,541 

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(a) Includes 1.2 million net acres retained in the 2016 divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.
Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to extend the terms of undeveloped leases we value, planning non-core divestitures to high-grade our lease inventory and letting some undeveloped leases expire that are no longer part of our development plans. We do not anticipate any material lease expirations within the next three years.

Marketing

The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, storage, processing and transportation services, contract administration and nomination services for us and other interest owners in Expand Energy-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of natural gas and oil production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received.
Generally, our natural gas and NGL production are sold to purchasers under index contracts or daily spot price contracts. Under our index contracts, the price we receive is tied to published indices. Under our daily spot price contracts, we receive the daily spot price at the location where the gas or NGL are sold. Oil production is sold under short-to-long-term market-sensitive and spot price contracts using a differential to NYMEX WTI.
We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 5 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of commitments.
As of December 31, 2025, we had delivery commitments for gas and NGLs of approximately 7,800 Bcf and 42 MMBbls over the next 20 and 17 years, respectively. These delivery commitments vary each year. Additionally, we have delivery commitments of approximately 4 MMBbls of oil during 2026. We expect to fulfill these commitments primarily with production from our proved developed reserves.
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Oilfield Services Vertical Integration

The Company also operates drilling rigs and provides certain oilfield products and services, principally serving the Company’s E&P operations through vertical integration.

Major Customers

For the year ended December 31, 2025, we had sales to one purchaser that accounted for 11% of our total revenues (before the effects of hedging). For the year ended December 31, 2024, we had no purchaser that accounted for 10% or greater of our total revenues (before the effects of hedging). For the year ended December 31, 2023, we had sales to two purchasers that accounted for approximately 17% and 10% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the years ended December 31, 2025 or 2023.

Competition

We compete with both major integrated and other independent natural gas and oil companies, as well as pipeline marketing affiliates and other marketing companies, in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.

Public Policy and Government Regulation

All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business. We anticipate that compliance with existing laws and regulations governing our current operations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, additional proposals that affect the oil and gas industry are regularly considered by presidential administrations, Congress, the states, regulatory agencies and the courts, and we cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following is a summary of the existing laws, rules and regulations to which our operations are subject.
Exploration and Production, Environmental, Health and Safety and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
• reporting of workplace injuries and illnesses;
• industrial hygiene monitoring;
• worker protection and workplace safety;
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• approval or permits to drill and to conduct operations;
• provision of financial assurances (such as bonds) covering drilling and well operations;
• calculation and disbursement of royalty payments and production taxes;
• seismic operations/data;
• location, drilling, cementing and casing of wells;
• well design and construction of pad and equipment;
• construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
• method of well completion and hydraulic fracturing;
• water withdrawal;
• well production and operations, including processing and gathering systems;
• emergency response, contingency plans and spill prevention plans;
• emissions and discharges permitting;
• climate change;
• use, transportation, storage and disposal of fluids and materials incidental to natural gas and oil operations;
• surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
• plugging and abandoning of wells; and
• transportation of production.

In November 2021, the Environmental Protection Agency (the “EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new, modified, reconstructed and existing facilities in the oil and gas sector. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The proposed rules sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (“CAA”) (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). The November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. In addition, the proposed rules sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In December 2023, the EPA issued the final rule, later published on March 8, 2024, which imposes more stringent requirements on the natural gas and oil industry, requiring all well sites and compressor stations to be routinely monitored for leaks and eliminating or minimizing emissions from common pieces of equipment used in oil and gas operations, such as process controllers, pumps, and storage tanks. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The March 8, 2024 final rule gave states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane from existing sources. Additionally, on January 17, 2025, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) issued a prepublication version of a final rule that requires pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to update leak detection and repair programs to require companies to use commercially available technologies to find and fix methane leaks from pipelines and other facilities. However, on January 20, 2025, the current Presidential Administration issued an Executive Order directing the heads of all federal agencies to identify and begin the process to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. As a result, the PHMSA leak detection rule, which had not yet been published in the Federal Register, was withdrawn prior to formal publication as PHMSA currently evaluates the
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rule’s requirements and cost-benefit analyses to ensure alignment with the current Presidential Administration’s energy and other policies. Subsequently, in March 2025, the EPA announced its intention to reconsider the March 8, 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026. Through a July 28, 2025 interim final rule, EPA extended the compliance deadlines for subparts OOOOb and OOOOc, later finalized on December 3, 2025. The December 2025 rule also gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. The final rule is subject to ongoing litigation but remains in effect. A broader reconsideration and potential full revision of the OOOOb and OOOOc rules was initially anticipated to be issued by EPA by September 2025 based on its Spring 2025 agenda, subject to delays. Consequently, the future implementation and enforcement of these rules remain uncertain at this time. These rules and policy priorities could have a material adverse effect on our financial position, results of operations and cash flows.

The Inflation Reduction Act (“IRA”), signed into law in August 2022, provides significant funding and incentives for research, development and implementation of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a Methane Emissions Reduction Program that amends the CAA to require the EPA to impose a Waste Emissions Charge (“WEC”) on methane emissions from certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. In May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the final rule expanded the emissions events that are subject to reporting requirements to include "other large release events" and applied reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program were to be the basis for any payments under the Methane Emissions Reduction Program in the IRA. Petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit Court of Appeals has commenced. However, in January 2025, the current Presidential Administration issued an Executive Order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, in March 2025, the current Presidential Administration signed Congress’ Joint Resolution of Disapproval of the WEC, and in May 2025, EPA issued a final rule to remove the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act delayed the effective date of the WEC until 2034. To the extent the WEC rule is again promulgated and implemented, the emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. In addition, in September 2025, EPA proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories and suspend program obligations for some sources subject to subpart W (which applies to emission sources in certain segments of the petroleum and natural gas industry) until 2034. Under the proposed rule, facilities in the natural gas distribution segment of subpart W would no longer report to EPA after reporting year 2024. Future implementation and enforcement of these rules remains uncertain at this time.

In January 2024, the previous Presidential Administration announced a temporary pause on pending decisions on exports of LNG to non-free trade agreement countries until the Department of Energy (“DOE”) can update the underlying analyses for authorizations, including an assessment of the impact of greenhouse gas (“GHG”) emissions. However, in January 2025, the current Presidential Administration issued an executive order directing the DOE to restart reviews of applications for approvals of LNG export projects as expeditiously as possible. Accordingly, the regulatory landscape governing the LNG industry remains subject to change.

In addition, several states and geographic regions in the United States have adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the EPA, and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. In 2021, the previous Presidential Administration recommitted the United States to the Paris Agreement and announced a goal of reducing the United States’ GHG emissions by 50-52% below 2005 levels by 2030. On January 20, 2025, the current Presidential Administration issued an Executive Order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. Additionally, on January 7, 2026, the current Presidential Administration announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential
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memorandum. However, various state and local governments in the U.S. have publicly committed to furthering the goals of the Paris Agreement and many of these efforts at the local, state and international levels are expected to continue.

In April 2024, the European Union adopted a regulation to track and reduce methane emissions in the energy sector, including requiring new monitoring, reporting and verification measures to be applied by importers of oil, natural gas and coal into the European Union by January 1, 2027, and the “maximum methane intensity values” must be met by 2030 and every year thereafter. Each member state will have the power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect. In December 2025, the European Commission introduced certain simplifications to the methane rule’s importer compliance requirements, subject to acceptance by individual EU country governments.

Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental parts of our business. To date, we have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, as well as the increasing number of climate-related commitments by capital providers, our capital expenditures and operating expenses related to compliance with environmental and safety and health regulations have increased over time and may continue to increase. In addition, in March 2024, the SEC released its final rule requiring public companies to disclose information regarding material climate-related risks. However, the SEC voluntarily stayed the final rule in April 2024 pending judicial review of multiple petitions challenging the rules and it is unclear when the rule will become effective, if ever. Although future implementation of the final rule and impact on our business is uncertain, compliance with the rule, as finalized, may result in additional legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources. For more information, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.”
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from gas and oil wells, and the unitization or pooling of gas and oil properties. In the United States, some states allow the statutory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop gas and oil properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of gas and oil we can produce from our wells and the number of wells or the locations at which we can drill. For further discussion, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.”
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could result in additional federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of natural gas, oil and NGLs that we are ultimately able to produce from our properties.

In April 2024, the BLM finalized regulations to reduce the waste of natural gas from gas and oil operations on federal and Tribal land. The rule became effective in June 2024. However, in May 2024, North Dakota, Texas, Montana, Wyoming and Utah challenged the rule in federal district court. In September 2024, the court granted a preliminary injunction enjoining BLM from enforcing the rule against the plaintiff states pending the outcome of the litigation, and the litigation remains ongoing. However, as previously noted, in January 2025, the current Presidential Administration issued an Executive Order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. The BLM has given notice that it is in the process of considering revisions to the final rule and has delayed enforcement of two provisions included in the April 2024 rule until December 10, 2026. The relevant provisions subject to delayed enforcement imposed measurement device and
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sampling requirements for flares flowing between 1,050 and 6,000 Mcf per month and required operators to submit Leak Detection and Repair plans to the state BLM office; however, the obligation to repair leaks required under the regulations remains in effect. The state litigation against the April 2024 rule has been temporarily suspended pending the BLM’s reconsideration of the April 2024 rule. Future implementation and enforcement of this rule is uncertain at this time. Any future restrictions surrounding onshore drilling and restrictions on the ability to obtain required permits could have a material adverse impact on our operations.
Obtaining environmental permits has the potential to delay the development and operation of natural gas and oil projects. Delays in obtaining permits or an inability to obtain new permits or permit modifications or renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
For further discussion, see Item 1A. Risk Factors - “Natural gas and oil operations are uncertain and involve substantial costs and risks.”

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.
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Operating Hazards and Insurance

The natural gas and oil business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of materials or pollutants. Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of defending against claims by government agencies or third parties, injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $350 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $25 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

Facilities

We own offices in Oklahoma City, Oklahoma and lease an office building in Spring, Texas. Additionally, we own or lease various field offices in cities or towns in the areas where we conduct our operations. In 2026, we announced that we will move our Company headquarters to Spring, Texas.
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Executive Officers

The list below details, as of February 18, 2026, the name of each of our executive officers, together with his or her age and positions held over the past five years.
Michael A. Wichterich, Chairman of the Board, Interim President and Chief Executive Officer
Michael A. (“Mike”) Wichterich , 58, has served as Interim President and Chief Executive Officer since February 2026. He has served as Chairman of the Board of Directors since February 2021, including Executive Chairman from October 2021 until December 2022, and previously served as Interim Chief Executive Officer from April 2021 to October 2021. Mr. Wichterich is Founder and Chief Executive Officer of Three Rivers Operating Company LLC, a private exploration and production company with a focus in the Permian Basin. Prior to founding Three Rivers Operating, Mr. Wichterich served as the Chief Financial Officer of Texas American Resources, New Braunfels Utilities and Mariner Energy. Additionally, Mr. Wichterich began his career with PricewaterhouseCoopers in its energy auditing practice. Mr. Wichterich also serves as a board member of Grizzly Energy. He earned a B.B.A. from the University of Texas.
Christopher W. Lacy, Executive Vice President - General Counsel and Corporate Secretary
Christopher W. (“Chris”) Lacy, 48, has served as Executive Vice President – General Counsel and Corporate Secretary since October 2024. Prior to that time, he served as Senior Vice President, General Counsel and Secretary at Southwestern Energy Company. Mr. Lacy joined Southwestern in 2014 as Chief Litigation Counsel and held various roles of progressively increasing responsibility. Before joining Southwestern, Chris was with Dewey & LeBouef, LLP and Ahmad, Zavitsanos, Anaipakos, Alavi & Mensing P.C. with a practice focused on high value and high stakes litigation. He has nearly 20 years of experience representing clients in the energy industry. Mr. Lacy earned his B.A. in Communication from the University of Texas and his juris doctorate from the University of Houston Law Center.
Brittany Raiford, Vice President, Interim Chief Financial Officer and Treasurer
Brittany Raiford, 40, has served as Vice President, Interim Chief Financial Officer and Treasurer since August 2025. Previously, Ms. Raiford served as Vice President – Treasurer for Expand Energy. Prior to joining Expand Energy, Ms. Raiford was Vice President – Investor Relations for Southwestern Energy. Ms. Raiford joined Southwestern Energy in 2011, serving in roles of increasing responsibility in accounting and finance. Ms. Raiford earned her B.B.A. in Accounting and M.S. in Finance from Texas A&M University.
Daniel F. Turco, Executive Vice President - Marketing and Commercial
Daniel F. (“Dan”) Turco, 46, has served as Executive Vice President – Marketing and Commercial since February 2025. Prior to joining Expand Energy, Mr. Turco served as Head of Global LNG Trading / Head of Asia Gas & Power Marketing in Singapore for ExxonMobil. Mr. Turco joined ExxonMobil in 2006 and has since held positions of increasing responsibility in upstream natural gas marketing and trading, spanning LNG, U.S., Europe and Asia gas markets. Mr. Turco began his career in oil and gas as an engineer. Mr. Turco earned an M.B.A. from Wilfrid Laurier University (Canada) and an Honors Bachelor of Applied Science, Civil Engineering & Management Science from the University of Waterloo (Canada).
Joshua J. Viets, Executive Vice President and Chief Operating Officer
Joshua J. (“Josh”) Viets, 47, has served as Executive Vice President and Chief Operating Officer since February 2022. Prior to joining Expand Energy, Mr. Viets worked for 20 years in operational positions of increasing importance at ConocoPhillips (NYSE: COP). He most recently served as Vice President, Delaware Basin and previously held leadership positions in operations, engineering, subsurface, and capital project across the ConocoPhillips portfolio. Mr. Viets earned a Bachelor of Science in Petroleum Engineering from Colorado School of Mines.
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Human Capital Resources

Employees
We had approximately 1,600 employees as of December 31, 2025. None of our employees were covered by collective bargaining agreements, and our management works to maintain good relations with our employees.
Values-Driven Culture
At Expand Energy, our core values are the foundation of our company. Serving as the lens through which we evaluate business decisions, our commitment to these values, in both words and actions builds a stronger, healthier Expand Energy, benefiting all our stakeholders. Our core values are:
• Stewardship - Safety and environmental stewardship require excellence in the ordinary
• Character - Integrity in every action
• Collaborate - Embrace diverse perspectives, confront the brutal facts, and speak with radical candor
• Learn - Commit to continuous improvement through humility, curiosity and constant learning
• Disrupt - Challenge the status quo to achieve better outcomes for energy consumers
We are committed to supporting inclusion within our organization. We believe building a fair, inclusive work culture is a key driver of our long-term success. We embrace the variety of backgrounds, perspectives and talents within our organization, leveraging strengths to pursue results and meaningful change for our company, employees, and stakeholders.
Own Safety, Lead Safety
Safety is more than a company metric. It is core to our commitment to leading a responsible energy future. We set and deliver robust safety standards, prioritizing the well-being of our employees and contractors. Our safety culture is championed by our Board of Directors and executive leadership team, owned by every employee and contractor and managed by our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our employees and contractors own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.
One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right, responsibility and authority to stop work if conditions are unsafe or could cause harm to the environment. Creating an incident-free work environment starts with setting clear expectations among employees and contractors regarding our Safe and Compliant Operations Policy, safety standards, and working to empower and equip individuals with the skills necessary to promote safety in their areas of work. The foundation of our safety culture is our Own Safety, Lead Safety motto, which encourages all workers on our locations to take personal responsibility for their safety and the safety of those around them. We have transitioned companywide to our Serious Incident and Fatality prevention model for more proactive hazard identification of exposures that could lead to a life-altering injury with verification processes that check for controls in place for these exposures.
Every year our HSER team provides targeted trainings based on safety performance analysis, job functions and location specific factors. Our training program includes a mix of in-person and virtual training, with greater emphasis on in-person instruction and includes all employees. Job-specific learning paths aim to exceed regulatory requirements and ensure employees are holistically prepared to execute their job functions safely and responsibly.

Expand Energy’s training philosophy values contractor training in the same manner as employees. We design contractor training to align as much as possible with employee training, encouraging synchronized knowledge sharing and understanding, critical to decreasing our cumulative incidents.

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Ethical Business Conduct
Expand Energy works hard to maintain the confidence of our stakeholders. We earn this trust by striving to act in an ethical manner to protect our people, the environment and the communities where we operate. This starts by driving accountability through all levels of the company and having systems in place to uphold our high standards for conduct. Strong governance practices begin at the top, providing our organization with clear guidelines to define standards for ethical behavior at every level. Each Expand Energy director, officer or employee, regardless of position, must abide by Expand Energy’s Code of Business Conduct (the "Code"), which is structured around our core values. Each year all employees are required to complete comprehensive training on the Code and related policies, the high standards expected of them, including that they will report actual or potential ethics concerns or Code violations.
Employee Wellness and Benefits
Supporting the individual well-being of our employees is foundational to our safety culture and success as a company. We champion healthy lifestyles and offer health resources. Across the company, employees are offered preventive programs and are encouraged to complete an annual screening for common health-related issues. We support our employees’ and their families’ health by offering full medical, dental, vision, prescription drug insurance for employees and their families, life insurance, short- and long-term disability coverage, and health savings and dependent care flexible spending accounts. We offer parental leave for the birth or adoption of a child, an adoption assistance program, alternate work schedules, a 401(k) savings plan with company match and discretionary contributions, flexible work hours, generous paid time off, including a well-being day, where each employee is encouraged to relax and recharge for a day once per calendar year and 12 company-paid holidays, as well as tuition reimbursement. Additionally, Expand Energy provides employees and their families access to a confidential Employee Assistance Program, which connects employees with trained counselors and other support professionals.
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Item 1A. Risk Factors

There are numerous factors that affect our business and results of operations, many of which are beyond our control. The following is a description of factors that we consider to be material and that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, results of operations, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Risks Related to Operating our Business

Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, results of operations, profitability, liquidity, leverage ratio and ability to grow and invest in capital expenditures depend primarily upon the prices we receive for the natural gas, oil and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas, oil and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas and oil prices may result in a reduction of the carrying value of our natural gas and oil properties due to recognizing impairments in proved and unproved properties.
Volatility in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
• domestic and worldwide supplies of natural gas, oil and NGL, including U.S. inventories of natural gas and oil reserves;
• weather conditions;
• changes in the level of consumer and industrial demand, including impacts from global or national health events and concerns;
• the price and availability of alternative fuels;
• technological advances affecting energy consumption;
• the nature and extent of domestic and international conservation and sustainability initiatives;
• the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
• the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
• U.S. exports of natural gas, oil, liquefied natural gas and NGL;
• the price and level of foreign imports;
• changes in U.S. trade relations and policies;
• the nature and extent of domestic and foreign governmental regulations and taxes;
• the ability of the members of OPEC+ and others to agree to and maintain oil price and production controls;
• increased use of competing energy products, including alternative energy sources;
• political instability or armed conflict in natural gas and oil producing regions, including in connection with the continued armed conflict between Russia and Ukraine, instability in the Middle East and Venezuela, and changes in China-Taiwan relations;
• acts of terrorism; and
• domestic and global economic and political conditions.
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These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements. In addition, any prolonged period of lower prices could reduce the quantities of reserves that we may economically produce.
Conservation measures and technological advances could reduce demand for natural gas and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.
Negative public perception regarding us or our industry could have an adverse effect on our operations.
Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement priorities. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations or those of our midstream transportation providers, encourage capital providers to divest of their interests in us or our industry, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating and compliance costs, additional regulatory scrutiny and increased risk of litigation, as well as potentially reducing our ability to execute routine or strategic business partnerships. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public can engage in the permitting process, including through intervention in the courts. Changes in public perception could cause the permits we require to conduct our operations to be withheld, delayed or conditioned by requirements that restrict our ability to conduct our business, which could materially adversely affect our industry and our financial condition and results of operations.
Certain financial institutions, funds and other sources of capital have also elected to restrict or eliminate their investment in certain fossil fuel-related activities, which may restrict our access to capital. Even if capital providers have not generally restricted their investment in fossil fuel-related activities, they may still assess various sustainability considerations in making voting and capital allocation decisions. Responding to these and other stakeholder concerns on sustainability matters may require us to incur additional costs or otherwise impact our business. In addition, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in reduced demand for our products or stimulate demand for alternative forms of energy that do not rely on combustion of fossil fuels. For more information, see our risk factor “Increasing attention to sustainability matters and our ability to achieve and maintain sustainability certifications, goals and commitments may impact our business, financial results or stock price.”
The gas and oil exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address industry challenges more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. In addition, the sudden loss of any of our key executives, their services or our failure to appropriately plan for any expected key executive succession could materially and
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adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
Risks related to potential acquisitions or dispositions may adversely affect our business.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments. These transactions may not result in the anticipated benefits or efficiencies. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition or disposition involves risks and we cannot assure you that:
• any acquisition will be successfully integrated into our operations and internal controls;
• the due diligence conducted prior to an acquisition will uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
• post-closing purchase price adjustments will be realized in our favor;
• our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses and costs will be accurate;
• there will not be delays in closing, lower than expected sales proceeds for the disposed assets or business, residual liabilities or post-closing claims for indemnification;
• any investment, acquisition or disposition will not divert management resources from the operation of our business; and
• any investment, acquisition or disposition will not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write-downs of the carrying value of our natural gas and oil properties.
We have been required to write down the carrying value of certain of our natural gas and oil properties in the past, and there is a risk that we will be required to take additional write-downs in the future. Write-downs may occur in the future when natural gas and oil prices are low for sustained periods, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs or due to the anticipated sale of properties.
The successful efforts method of accounting requires that we periodically review the carrying value of our natural gas and oil properties for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write-down the carrying value of a property based on natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity and other factors. A write-down constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment, reduces our reported earnings and increases certain leverage ratios. See Impairments within Critical Accounting Estimates included in Item 7 of this report for further information.
Significant capital expenditures are required to replace our reserves and conduct our business.
Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, and to the extent that is not sufficient, borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and NGLs, our success in developing and producing new reserves and the other risk factors discussed herein. Our forecasted 2026 capital expenditures, inclusive of capitalized interest, are $2.75 - $2.95 billion compared to our 2025 capital spending level
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of $2.85 billion. Management continues to review operational plans for 2026 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of natural gas, oil and NGLs. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our natural gas, oil and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future natural gas and oil reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
As of December 31, 2025, approximately 28% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans for capital expenditures to convert PUDs into proved developed reserves, including approximately $4.2 billion during the next five years. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2025 present value is based on the price of $3.39 per Mcf of natural gas, $65.34 per bbl of oil and $65.34 per bbl of NGL, before basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for natural gas and oil, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the gas and oil industry in general will affect the appropriateness of the 10% discount factor.
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Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, federal restrictions on gas and oil leasing and permitting and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGLs, costs associated with producing natural gas, oil and NGLs and our ability to add reserves at an acceptable cost.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties or drilling a well, whether natural gas or oil is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on natural gas and oil properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if we believe the pricing environment for certain time periods is unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
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Most of our natural gas, oil and NGL derivative contracts are with counterparties under bilateral hedging arrangements. Our counterparties’ obligations under the arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. Collateral requirements are dependent to a large extent on natural gas and oil prices.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on their obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Natural gas and oil operations are uncertain and involve substantial costs and risks.
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive gas or oil reservoirs. Drilling for natural gas, oil and NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop gas and oil properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Although both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our gas and oil properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
• unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
• equipment failures or accidents;
• repairs or maintenance of older assets;
• fires, explosions, blowouts, cratering or loss of well control;
• the mishandling or underground migration of fluids and chemicals;
• adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;    
• issues with title or in receiving governmental permits or approvals;
• restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
• environmental hazards or liabilities;
• restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
• shortages or delays in the availability of services or delivery of equipment; and
• unexpected or unforeseen changes in regulatory policy, and political or public opinion.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.
Moreover, certain of these events could result in environmental contamination and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death, significant damage to property and natural resources or significant financial liabilities or penalties.
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Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in compliance with environmental laws.

Water is an essential component of natural gas, oil and NGL production during both the drilling and hydraulic fracturing processes. Development activities, particularly hydraulic fracturing, require the use and disposal of significant quantities of water. Over the past several years, portions of the country have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. In these areas, water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. The imposition of new or revised environmental regulations could further restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of natural gas and oil.

We have made significant investments in gathering and transportation assets and oilfield service businesses, including joint ventures in gas gathering pipelines, our drilling rigs, water infrastructure and pressure pumping equipment, and may rely on such investments in third parties to lower costs and secure inputs for our operations and transportation for our production. If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.

We depend on third-party pipelines and other investments to provide us certain gathering and transportation assets. During the fourth quarter of 2022, we entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture project, the New Generation Gas Gathering pipeline (the “NG3 pipeline”), to gather and treat natural gas produced in the Haynesville Shale for delivery to Gulf Coast markets, including LNG export. We have a 35% interest in the joint venture entity. On October 1, 2025, the NG3 pipeline was placed in service and began gathering operations. We rely on the NG3 pipeline to provide to us certain gathering, processing and transportation services. We have a gathering agreement in which approximately 900 MMcf per day, on average, of natural gas are to be gathered and processed by the NG3 pipeline over the course of the next 12 years. In the event that the services of the NG3 pipeline are impacted due to repairs, damage to the facility, lack of capacity or any other reason, our ability to lower costs and secure inputs for our operations and transportation for our production may be impacted.

We also have made investments to meet certain of our field services’ needs. If our level of operations is reduced for a long period, we may not be able to recover these investments. Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our natural gas, oil and NGL gathering needs. Because we do not own and/or control these third-party pipelines or facilities, such as the NG3 pipeline, their continuing operation and access requirements are not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas, oil and NGL due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and ship natural gas, oil and NGL to end markets could be restricted. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, cash flows, and results of operations. Capital constraints or changes in laws or regulations could limit the construction of new pipelines and gathering systems and the provision or expansion of trucking services by third parties. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated
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environmental impacts, and the increasingly negative public perception regarding, and opposition to, the oil and gas industry, including major pipeline projects. Until this new capacity is available, we may experience delays in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in our wells while awaiting a pipeline connection or additional capacity, which would adversely affect our results of operations. Capital constraints or changes in laws or regulations also could increase the cost to access to such capacity, which would increase the cost of our operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
We entered into a joint venture, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests and these joint ventures are subject to many of the same risks to which we are subject.
We entered into a joint venture primarily pertaining to the building of a new natural gas gathering pipeline and carbon capture project, the NG3 pipeline, and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. Because we do not control all of the decisions of our joint ventures or joint venture partners, either because we do not have a controlling interest in the venture or are not an operator under the agreement, it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture's best interests, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may significantly adversely affect the ability to complete the project. In addition, such joint ventures may be subject to many of the same risks to which we are subject.
Our business strategy includes participating in the global LNG value chain, which is dependent, in part, on the growing U.S. LNG export market, a highly regulated and capital intensive industry with a number of inherent commercial risks. U.S. LNG exports have helped drive domestic demand for natural gas, and, as a natural gas producer, we could be materially and adversely impacted by a deterioration in the U.S. LNG export industry, which could in turn reduce demand for natural gas. In addition, we may seek to more directly participate in the LNG value chain through direct marketing arrangements with LNG export facilities and/or end users, which could expose us to additional commercial risks associated with the global LNG markets.
As a domestic natural gas exploration and production company, we may be indirectly exposed to certain risks in the U.S. LNG export markets, including to the extent that we have entered into, or may in the future enter into, long-term natural gas supply agreements with LNG export facilities. The LNG export industry is a highly regulated and capital-intensive industry that is subject to a number of risks. Many facilities remain under construction or are expanding, and if these facilities are unable to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of their facilities, or if they are unable to secure financing in connection with their operations or the completion of their planned projects, the U.S. LNG market may be materially and adversely impacted, which could reduce demand for U.S. natural gas and have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may also in the future enter into other commercial arrangements directly with foreign LNG customers. LNG sale and purchase agreements commonly have terms exceeding 10 years, which could expose us to credit risk should a customer default and we are required to seek recourse. Additionally, long-term LNG sales and purchase agreements generally permit a customer to terminate their contractual obligations upon the occurrence of certain events, including: (i) a failure to make available specified scheduled cargo quantities, (ii) delays in the
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commencement of commercial operations and (iii) the occurrence of certain events of force majeure. The occurrence of these and other events permitting termination may be outside of our control and may expose us to unrecoverable losses.
Further, any future commercial agreement may expose us to commodity risks associated with differential pricing of natural gas in different markets. LNG and natural gas are traded according to prices determined with reference to a variety of international indices, including the Japan Korea Marker (JKM) and the Dutch TTF market, each of which may materially differ from prices that use the U.S. Henry Hub index as a reference price. If we are unable to manage the impacts of unfavorable price differentials between domestic and international indices for LNG or natural gas in the context of future agreements, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The departure of key management personnel and the failure to attract and retain talent could adversely affect our operations.
Our success depends upon the continued contributions of our senior executives. If one or more of our executive officers are unable or unwilling to continue in their current positions, we may not be able to replace them readily, if at all. Additionally, we may incur additional expenses to recruit and retain new executive officers. Because of these factors, the loss of any one or more members of our executive management team, for any reason, including resignation or retirement, could impair our ability to execute our business strategy and have a material adverse effect on our business, financial condition, and results of operations.
Although we have endeavored to implement these management transitions in a non-disruptive manner, such transitions can be inherently difficult to manage and may hamper our ability to meet our financial and operational goals. Such changes may also give rise to uncertainty among our customers, investors, vendors, employees and others concerning our future direction and performance. Any of the foregoing could result in significant disruptions to our operations and may adversely affect our financial condition, results of operations and ability to execute on our business plans.
Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.
Cybersecurity threats present a large and growing risk to our business, as the energy industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. For example, we depend on sophisticated information technology (“IT”) and operational technology (“OT”) to estimate quantities of natural gas, oil and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. In addition, many third-party providers directly or indirectly provide us products and services across an array of internal and external functions that are designed to enable us to conduct, monitor and/or protect our business, systems and data assets. In addition, in the ordinary course of business, we and our service providers collect, process, transmit, and store proprietary and confidential data, including personal information.

We have been, and we and our customers, business partners, and counterparties may become, the subject of cyber-attacks on our and their internal IT and OT systems and through those of third parties. Any such cyber-attacks or information security breaches could have a material adverse effect on our business and financial results and increase our operating and capital costs, as well as disrupt our business plans and negatively impact our reputation and operations. As an energy company, we expect to continue to be a target for such attacks in the future from nation-state sponsored foreign actors and other attackers. We face evolving cybersecurity risks that threaten the confidentiality, integrity and availability of our digital technologies and business data, including malicious attacks by third parties or insiders, social engineering/phishing and human error, as well as bugs, misconfigurations of hardware or software and other vulnerabilities that may exist in our or our third-party providers’ systems or technologies. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems do not function properly or our cybersecurity is breached or otherwise insufficient, we could suffer disruptions to our normal operations,
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which may include disruptions to our drilling, completion, production and corporate functions. There can also be no assurance that our cybersecurity risk management program and processes, including our policies, controls or procedures, will be fully implemented, complied with or effective in protecting our systems and data. A cyber-attack, or the perception thereof, involving our information systems and related infrastructure, or that of our business associates or third-party providers, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including expensive and time-consuming costs to repair or restore our systems and data or to take other remedial steps, disproportionate attention of management, or damage to our reputation. Additionally, rapidly evolving laws and regulations governing cybersecurity pose increasingly complex compliance obligations and technical challenges, and failure to comply with these obligations, including incident notification requirements, could result in legal claims or proceedings (such as class actions), regulatory investigations and enforcement actions, fines and penalties and negative reputational impacts that could cause us to lose existing or future customers.

In the event of a cyber-attack, we may be required by federal and state laws or regulations to provide notification to regulators or individuals. For example, the Cyber Incident Reporting for Critical Infrastructure Act (CIRCIA) was signed into law on March 15, 2022. CIRCIA mandates that all owners and operators of critical infrastructure report cyber incidents to the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) within 72 hours and ransomware payments within 24 hours. These new requirements will become effective once CISA promulgates rules pursuant to the CIRCIA. CISA issued a notice of proposed rulemaking on April 4, 2024 and is expected to publish the final rule in May 2026.
Both the frequency and magnitude of cyberattacks is expected to increase as attackers are becoming more sophisticated and artificial intelligence proliferates. As a result, we may be unable to anticipate, detect, prevent, investigate or contain future attacks, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection and to remove or obfuscate forensic evidence. Further, global remote working dynamics for our customers, employees and third-party providers present additional risk that threat actors may seek to engage in social engineering (for example, phishing) and to exploit vulnerabilities in corporate and non-corporate networks. As cyber-attacks continue to evolve, including the prevalence of reconnaissance or surveillance by threat actors, which may remain undetected for an extended period notwithstanding our monitoring and detection efforts, we may be required to spend significant additional resources to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks of our IT and OT systems.
Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any or all of our insurance policies.

We collect, process, store and use personal information and other data, and our actual or perceived failure to protect such information and data or comply with data privacy and security laws and regulations could damage our reputation and brand and harm our business and operating results.

Along with our own data and information that we collect and retain in the normal course of our business, we and our business partners collect and retain significant volumes of certain other types of data, some of which are subject to data protection laws, including information related to our past, current and prospective employees, royalty owners, and other parties. The regulatory environment surrounding the collection, use, transfer and protection of such data, both domestically and internationally, is becoming increasingly complex, constantly evolving, and is subject to frequent significant change. We and our vendors are subject to a variety of federal and state data privacy laws, rules, regulations, industry standards and other requirements governing data privacy and the unauthorized disclosure of confidential information. Complying with these jurisdictional requirements could increase the costs and complexity of compliance procedures, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, we are subject to various state privacy laws, such as the California Consumer Privacy Act (“CCPA”), which came into effect in January 2020, and the California Privacy Rights Act (“CPRA”), which expands upon the CCPA and came into effect in January 2023 (with a lookback period beginning January 2022). The CCPA and the CPRA, among other things, contain new disclosure obligations for businesses that collect personal information about California residents, provide such individuals expanded rights to
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access, delete and correct their personal information and opt-out of certain sales or transfers of personal information and provide for statutory fines and penalties for certain data security breaches or other CCPA and CPRA violations. The enactment of the CCPA has prompted a wave of similar legislative developments in other states in the United States, which creates the potential for a patchwork of overlapping but different state laws. Any failure or perceived failure by us to comply with data privacy laws, rules, regulations, industry standards and other requirements could result in proceedings or actions against us by individuals, consumer rights groups, government agencies or others. We could incur significant costs in investigating and defending such claims and, if found liable, pay significant damages or fines or be required to make changes to our business. Further, any such proceedings and any subsequent adverse outcomes may subject us to significant negative publicity and an erosion of trust. If any of these events were to occur, our business, reputation, financial condition or results of operations could be materially adversely affected.
Our business is subject to risks related to catastrophes, natural disasters, severe weather and human causes beyond our control, which may have a negative impact on our results of operations and financial condition.

Our operations are subject to disruption from human causes beyond our control and natural disasters, including extreme weather events the scientific community has concluded are associated with climate change, such as hurricanes, severe storms, floods, droughts, heat waves, winter storms, wildfires and ambient temperature, water level or precipitation changes as well as war, accidents, civil unrest, political events, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases, any of which could result in suspension of operations (including those of our customers or suppliers) or harm to people, our assets or the environment.

It is difficult to predict with certainty the timing, frequency or severity of such events or how such frequency or severity may change. However, if any such events were to occur, potential adverse effects could include disruption of our production activities, delays in production or possibly shut-ins as a result of physical damage to wells, pumps, storage tanks and other infrastructure facilities, increases in our costs of operation or reductions in the efficiency of our operations, reduced availability of electrical power, road accessibility, and transportation facilities, impacts on our personnel, supply chain, distribution chain or customers, and potentially increased costs or limited availability for insurance coverages in the aftermath of such effects. Such events could also adversely affect or delay demand for our products or cause us to incur significant costs in preparing for, or responding to, the effects of climatic or weather events themselves. Any such events could have a material adverse effect on our results of operations or financial condition. Moreover, any changes in ambient temperatures or severe weather events may impact demand for natural gas if it results in lower energy needs for, among other things, temperature control.