EXPAND ENERGY Corp (EXE) Business

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:

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

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:

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(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.

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(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:

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.

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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.