NASDAQ: EXE

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.

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.

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

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(a) Excludes the effect of hedging.

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

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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.

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,

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.

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.

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;

•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

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

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