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3Q 2025 Earnings OCTOBER 28, 2025
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This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amen ded, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward -looking statements include our current expectat ions or forecasts of future events, including matters relating to armed conflict and instability in Europe and the Middle East, along with the effects of the cur rent global economic environment, and the impact of each on our business, financial condition, results of operations and cash fl ows, 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, our ability to capture synergies, the amount and timing of any cash dividends and our environmental, social and governance (“ESG”) initiatives. Forward-looking and other statements in this presentation regarding our environmental , social and other sustainability plans and goals are not an indication that these statements are necessarily material to inv estors or required to be disclosed in our filings with the Securities and Exchange Commission (“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, inter nal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Forward -looking statements often address our expected futur e business, financial performance and financial condition, and often contain words such as “aim”, “predict”, “should”, “expec t,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy.” The absence of such words or expressions does not necessarily mean the statements are not forwar d-looking. Although we believe the expectations and forecasts reflected in our forward -looking statements are reasonable, they are inherent ly subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our contr ol. 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 (“NGLs”); ▪ 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 productio n 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 regulation s; ▪ disruption of our business by natural or human causes beyond our control; ▪ 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 and instability in Europe and the Middle East, along with the effects of the curre nt 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 retention and 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 informa tion technology systems, or from breaches of information technology systems of third parties with whom we transact business; ▪ our ability to achieve and maintain ESG certifications, goals and commitments; ▪ legislative, regulatory and ESG initiatives, including those addressing the impact of climate change or further regulating hy draulic 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 our merger with Southwestern Energy Company (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 our Annual Report on Form 10 -K filed with the SEC. This presentation references non-GAAP financial measures and metrics, including certain forward -looking information regarding such measures that are not reconcilable with GAAP measures due to their inherent uncertainty. Please see Appendix, which includ es definitions of non-GAAP measures and metrics used in this presentation and reconciliations of non -GAAP measures to the most directly comparable GAAP mea sure. We caution you not to place undue reliance on the forward-looking statements contained in this presentation, which speak only as of the filing date, and we undertake no obligation and have no intention to update any forward -looking statement, except as req uired by law. We urge you to carefully review and consider the disclosures in this presentation and our filings with the SEC that attempt to advise interested parti es 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. Forward-Looking Statements 2 3Q 2025 Earnings
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3Q25 Operational and Financial Highlights 3 Further Reduced FY25 Capex by ~$75mm Positioned to produce ~7.5 Bcfe/d for ~$2.85bn capex in 2026 Largest Domestic Natural Gas Producer: ~7.3 Bcfe/d 3Q25 beat with: ~$1.1bn of adj. EBITDAX (1) ~$735mm of capex Expanding Our Haynesville Advantage Delivering best-in-basin capex and productivity, leading to <$2.75 breakeven ~$1.2bn Gross Debt Reduction in Last 12 Months Multi-year deleveraging effort to improve full-cycle balance sheet capacity 3Q 2025 Earnings Upsized Credit Facility to $3.5bn Enhanced liquidity and extended maturity to 2030 Signed 15-year SPA with Lake Charles Methanol Sole natural gas supplier to new-build facility with start date in ~2030, pricing premium to NYMEX (1) Adjusted EBITDAX is a non-GAAP financial measure, see Appendix for more information and a reconciliation to the most directly co mparable GAAP financial measure
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Scale: Largest natural gas producer in North America with ~1.9mm net acres, ~7.15 Bcfe/d in 2025 Flexibility: Highly complementary asset base offers capital allocation flexibility Growth: Differentiated ability to accretively grow volumes (when supply is needed) Location: Unique access to premium markets and highest value demand centers Longevity: Deep inventory supporting returns for decades (20+ years (1) ) Attractive, Connected Portfolio 3Q 2025 Earnings4 Northeast Appalachia ~700,000 net acres >1,500 gross locations FY25E Prod: ~2,600 MMcfe/d Haynesville ~664,000 net acres >2,000 gross locations FY25E Prod: ~3,000 MMcfe/d Southwest Appalachia ~566,000 net acres >1,500 gross locations FY25E Prod: ~1,550 MMcfe/d Superior Portfolio Characteristics Net acres and gross locations as of Dec. 31, 2024 (1) >5,000 gross locations divided by ~250 annual TILs
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~$1,140 $2,410 ~$2,600~$440 ~$530 ~$300 ~$190 ~$250 Haynesville Northeast App Southwest App Other Field Corporate 2025E Capex Improved 2025 Capital Outlook 5 ~$2.85bn • Leasehold • Workover • PP&E • G&A • Capitalized interest Delivers ~7.15 Bcfe/d in 2025 Productive capacity build (+300 MMcfe/d by 1Q26) 2025 Capital Expenditures (Implied Midpoints of 2025 Guidance, $mm) 3Q 2025 Earnings ▪ Reduced FY25 capex spend by additional ~$75mm ▪ Record operational performance driving capital efficiencies ▪ ~300 MMcfe/d of available productive capacity by 2026 ~$150mm improvement to original FY25 guidance
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2025 Production Outlook 6 Rigs 2 2 2 3 2 – 3 Crews 2 2 2 2 2 2,668 2,662 2,556 ~2,500 ~2,600 1Q25A 2Q25A 3Q25A 4Q25E FY25E Northeast Appalachia Quarterly Production (MMcfe/d) 1,503 1,562 1,571 ~1,550 ~1,550 1Q25A 2Q25A 3Q25A 4Q25E FY25E Southwest Appalachia Quarterly Production (MMcfe/d) ▪ Strong well performance and reduced midstream downtime in Haynesville ▪ Weak in-basin pricing led to voluntary curtailments in Appalachia ▪ 4Q25 production will be responsive to market conditions with volume expected to increase through quarter ▪ Delivering FY25 guided well counts with fewer rigs 3Q 2025 Earnings 2,617 2,978 3,206 ~3,200 ~3,000 1Q25A 2Q25A 3Q25A 4Q25E FY25E Haynesville Quarterly Production (MMcfe/d) Rigs 7 7 7 6 – 7 7 Crews 3 4 4 3 3 – 4 Rigs 2 2 2 2 2 Crews 2 1 1 1 1 – 2
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Mid-cycle Price, $/Mcf $2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $4.00 $4.25 $4.50 6.75 $2.4 7.00 $2.6 7.25 $2.7 7.50 $2.9 7.75 $3.1 8.00 $3.3 8.25 $3.6 Optimizing Maintenance Production to Maximize Free Cash Flow (1) 7 Selected mid-cycle production target is continually evaluated for changing market dynamics Centering activity to deliver ~7.5 Bcfe/d through-cycle maximizes FCF at mid-cycle prices between $3.50 to $4.00 Maximum FCF Minimum FCF *For a given mid-cycle price Outlook (e.g., column) Maintenance Capital(3), $bn Maintenance Production, Bcfe/d 3Q 2025 Earnings (1) FCF is a non-GAAP financial measure, see Appendix for more information (2) Modeled FCF is not specific to a particular forward year, but representative of run -rate / maintenance production and capital at a given price excluding any hedges and inclusive of all forecasted synergies (3) Total capital inclusive of D&C, non-D&C field and non-D&C corporate; utilizes current cost assumptions (no inflation) as of Febr uary 2025 Illustrative Annual FCF (2) at Various Mid-cycle Prices, Maintenance Production and Capital
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Productive Capacity Success Story 3Q 2025 Earnings (1) FCF is a non-GAAP financial measure, see Appendix for more information (2) Calculated as the difference between FCF that would have been generated in the 12 -month period following the original TIL date f or the ~140 wells deferred in 2024 versus the FCF generated in the 12 -month period following the actual, or currently scheduled, TIL date 8 Productive Capacity FCF (If TIL'd in 2024) Productive Capacity FCF (As Planned) Illustrative Productive Capacity Strategy Productive Capacity Generates Significant Value ~$225mm increase in FCF(1) over first 12 months of volume from productive capacity wells(2) ▪ Incorporating learnings from prior execution to further refine operational agility ▪ Positioned to produce 7.5 Bcfe/d in 2026; supply-demand fundamentals will dictate timing of production response ▪ Unchanged view of mid-cycle price; productive capacity strategy built to manage through volatility Mid-cycle Production Target Capital Allocation Response Production Above Target Production Below Target OVERPRODUCING BAND UNDERPRODUCING BAND ~7.5 Bcfe/d midpoint aligns with $3.50 – $4.00 mid-cycle price
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Dynamics of Significant Growth Markets GLOBAL LNG: ▪ More than 40% demand growth by 2030, an increase of 27 Bcf/d ▪ Opportunity for Expand: Connect reliable, lower-carbon supply to global customers, diversify revenue stream, increase optionality, integrate value chain U.S. GULF COAST AND TEXAS: ▪ LNG feed gas demand set to double by the end of the decade ▪ Local industrial and power demand surging ▪ Significant new infrastructure required to meet demand ▪ Opportunity for Expand: Premium pricing for wellhead-to-delivery certified gas, competition for reliable and flexible feed gas supply, positioned to supply demand growth, strategic infrastructure investments NORTHEAST: ▪ Increasing local demand from data centers, power generation, coal retirements/conversions leads to an additional 4 Bcf/d of demand ▪ Possible new infrastructure build ▪ Opportunity for Expand: Long-term structured sales, bespoke products for customers in need of flexibility and reliability, increased partnerships with industrials, utilities and power generators Connecting Global Scale to Growing Markets 3Q 2025 Earnings9 Expand has differentiated access to growing natural gas demand EXE estimates based on EIA data, FERC filings and public statements (1) Texas includes LNG west of Sabine River Corridor and estimated power and industrial demand in Texas; Sabine Pass, Golden Pass and Port Arthur LNG included in U.S. Gulf Coast, along with LNG and estimated power and industrial demand in Louisiana NE APP HAYNESVILLE SW APP MIDWEST DEMAND SOUTHEAST DEMAND GLOBAL LNG DEMAND TEXAS DEMAND(1) 2025 Demand Bcf/d 2030 Demand Gain Bcf/d U.S. GULF COAST DEMAND(1) NORTHEAST DEMAND FLORIDA DEMAND +1 Bcf/d 15 Bcf/d +27 Bcf/d 60 Bcf/d +11 Bcf/d 14 +1 Bcf/d +2 Bcf/d 4 +4 Bcf/d 19 Bcf/d +8 Bcf/d 17 Bcf/d 7 +2 Bcf/d EXPORTS TO MEXICO 5
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Expanding the Value of Natural Gas 3Q 2025 Earnings10 Sample Commercial Activities • Daily optimization • Increased end-user sales • Gas supply and management agreements • Strategic infrastructure investment to enhance market connectivity • Storage and balancing agreements • Wellhead-to-delivery certified gas sales • Actively managed hedge portfolio • Long-term supply deals underpinning growing demand sources • Bespoke structured gas, power and LNG transactions • Strategic value-chain partnerships • Asset management agreements Guiding Principles of Value Creation Mitigate Volatility of Cash Flows Provide Customers Reliability and Flexibility Facilitate Premium Market Demand Act on Global Fundamental Insights Enhance and Capture Optionality Value C O M P R E H E N S I V E R I S K M A N A G E M E N T Recent Progress: Lake Charles Methanol Supply Agreement Sole natural gas supplier to new-build facility with start date in ~2030, pricing premium to NYMEX
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Proximity to Diversified Demand Growth EXE Haynesville has access to tangible LNG, power and industrial demand ▪ Lake Charles Methanol Supply Agreement • Facilitating new industrial demand in Louisiana • Wellhead-to-delivery certified gas sale creating low-carbon blue methanol with committed global offtake • 15-year gas sales agreement beginning in 2030; expect FID in 2026 • Sole supplier with baseload 325 MMcf/d and up to 50 MMcf/d additional sales • Pricing premium to NYMEX ▪ Haynesville Demand Dynamics • Concentrated demand growth within Louisiana and immediate adjacent regions exceeds expected supply • Total demand growth of ~11 Bcf/d by 2030 • ~80% of growth from LNG; >2 Bcf/d of power and industrial demand growth by 2030 • Customers seeking to secure long-term supply for projects in development and construction phases • Limited pipeline capacity from associated gas basins, expect to compete for supply with growing demand in Texas and Mexico 3Q 2025 Earnings11 EXE’s Gillis Capacity: ~2.5 Bcf/d Lake Charles Methanol +2.3 Bcf/d POWER/INDUSTRIAL DEMAND EXE’s Perryville Capacity: ~2 Bcf/d 2025 Demand Bcf/d 2030 Demand Gain Bcf/d Online LNG Under Construction LNG FERC and DOE Approved LNG EXE Haynesville Acreage EXE estimates based on EIA data, FERC filings and public statements (1) LNG Feed Gas Demand includes LNG facilities in Louisiana as well as Sabine Pass, Golden Pass and Port Arthur LNG, which are l ocated at the border of Texas and Louisiana 4.4 Bcf/d +8.7 Bcf/d LNG FEED GAS DEMAND (1)9.6 Bcf/d
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806 812 783 ~835 ~855 2022 2023 2024 2025E 2026E Productivity Improving Through Time (12 mo. Mcfe/ft.) 12 ▪ Optimization of development plan and completion design improving productivity through time ▪ Average EXE well productivity (1) was ~40% greater than basin average 2022 – 2025 (1) ; expect trend to continue ▪ ~20% of FY25 TILs have 12-month cum. >1 Bcfe/1,000 ft. Haynesville Capital Efficiency Improvements Yielding <$2.75 Breakeven ~5% increase in well performance since 2023 3Q 2025 Earnings $1,657 $1,847 $1,573 ~$1,370 ~$1,340 2022 2023 2024 2025E 2026E Demonstrating Continued Capital Improvements ($/ft.) (2) >25% reduction in well costs since 2023 ▪ Drilling synergies, deflation capture and company-owned sand mine driving significant capital cost savings ▪ Non-operated wells year-to-date show average EXE capex/ft. >30% lower than peers (3) in like-for-like areas ▪ Synergies driving production expense down ~15% from original FY25 guidance Annual asset-level breakeven excludes corporate items (1) 12-month cumulative Mcfe/1,000 ft.; peer data sourced from Enverus (2) Historical cost per foot is inclusive of both Legacy CHK and Legacy SWN actuals (3) Data reflects actual non-operated capex spend Basin-leading well performance with ~20 years of durable inventory
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SW Appalachia ▪ Acquired ~7,500 acres located in the Core Marcellus (Monroe County, OH and Marshall County, WV) for $57mm during the third quarter ▪ Adds ~425,000 lateral feet for the equivalent of >40 locations (1) • Low-cost inventory in the form of lateral extensions and 6 new locations with laterals greater than 18,000′ • Lateral extensions more than double the existing lateral length of 24 development wells to an average of 24,000′ ▪ Highly synergistic acreage with all locations developed from existing EXE pad sites scheduled for near-term development between 2026 – 2028 Western Haynesville ▪ Established 75,000+ net-acre position in Western Haynesville for $178mm (2) through targeted leasing and an undeveloped leasehold acquisition ▪ Bobby Yancey vertical appraisal well validated presence of high-quality shale ▪ Horizontal well planned for 4Q25 to assess reservoir deliverability ▪ Presents upside to Haynesville inventory with potential to unlock >200 locations (1) Attractive, Low-Cost Inventory Additions 3Q 2025 Earnings (1) 10K normalized laterals (2) Includes targeted leasing and an undeveloped leasehold acquisition; Acquisition consideration includes cash of ~$117mm in 2H2 5 and ~$29mm of capital carry expected to be incurred over the next two years 13 T E X A S 75,000+ net acres of prospective Western Haynesville L O U I S I A N A Recent land and leasehold acquisitions yield ~240 net undeveloped locations (1) at <$1mm each
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$2.30/ share $500mm Var Div. / Buyback 75% $500mm Cash 25% $116mm Total FCF Additional Returns to Equity Net Debt Reduction Annual Base Dividend ▪ Tranche 1 – Annual Base Dividend • $2.30/share • Remains priority and is paid through-cycle • 3Q25 DPS of $0.575/sh to be paid in December ▪ Tranche 2 – Net Debt Reduction • Allocating $1bn to net debt reduction • Pursuing a multi-year deleveraging effort to improve through-cycle balance sheet capacity ▪ Tranche 3 – Additional Returns to Equity • 75% of remaining FCF in form of equity return (variable dividend or share repurchases) • $211mm variable dividend and $100mm share repurchases in 1H25 Enhanced Capital Returns Framework 3Q 2025 Earnings14 Additional Returns to Equity (1,2) EXCESS FCF REMAINING FCF (1) $116mm related to Eagle Ford divestitures (2) Net Debt and FCF are non-GAAP financial measures, see Appendix for more information (2)
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▪ Current balance sheet is strong, however additional deleveraging creates more capacity at cycle-lows ▪ Pursuing a multi-year deleveraging effort to improve through-cycle balance sheet capacity ▪ Deleveraging should occur at good prices to facilitate more consistent and aggressive payouts through-cycle ▪ If market conditions change, we remain flexible to pivot to more aggressive repurchasing Investment Grade Balance Sheet Supports Through-Cycle Value Creation 3Q 2025 Earnings15 (1) Assumes $70/bbl WTI and 40% NGL (2) As of 9/30/2025 $847 6.75% $1,200 $1,150 $440 5.875% $3,500 $638 5.375% $750 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Debt Maturity Profile (BBB-, Baa3, BBB-) ($mm)(2) ~6.10% ~5.50% 5.375% 4.75% 5.70% ~$2.6 ~$3.9 ~$5.1 ~$6.4 ~$7.6 $2.50 $3.00 $3.50 $4.00 $4.50 Unhedged Run-Rate EBITDAX ($bn)(1) Further prioritization of debt pay down will facilitate attractive value creation at lower prices Callable debt EXE RBL Capacity
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$3.47 $4.10 $3.73 $4.05 $4.36 $4.49 $3.54 $3.80 $4.59 $4.82 $4.52 $4.60 $4.63 $4.85 $4.37 $4.10 $3.46 $3.55 $3.58 $3.61 $3.70 $3.75 $3.72 $3.84 4Q25 1Q26 2Q26 3Q26 4Q26 1Q27 2Q27 3Q27 Current Hedge Position Preserves Upside and Downside Protection 16 344 321 254 235 176 113 45 2 18 55 51 42 54 50 50 51 4Q25 1Q26 2Q26 3Q26 4Q26 1Q27 2Q27 3Q27 Hedged Natural Gas Volumes Current Hedge Book Supports Near-Term Realizations and Preserves Upside Ceiling and Floor (1) ($/MMbtu) Realized Price Strip 3Q 2025 Earnings Added since 2Q Earnings (Bcf) Last Public Disclosure (Bcf) 59% hedged in 4Q25 47% hedged in 2026 (1) As of 10/22/2025
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Expanding Returns, Expanding Opportunities Attractive, Connected Portfolio Peer-leading Returns Resilient Financial Foundation Responsible Stewardship Premium rock, returns, runway with access to premium markets Most efficient operator with proven track record of delivering returns to shareholders Investment Grade balance sheet provides strategic through-cycle advantages Connecting affordable, reliable and lower carbon energy to markets in need 3Q 2025 Earnings17
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Appendix 3Q 2025 EARNINGS
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Management’s Guidance as of October 28, 2025 19 Production (MMcfe/d) 3Q25A 4Q25E 2025E Total Production 7,333 7,200 – 7,300 7,100 – 7,200 Haynesville 3,206 ~3,200 ~3,000 Northeast Appalachia 2,556 ~2,500 ~2,600 Southwest Appalachia 1,571 ~1,550 ~1,550 Capital Expenditures ($mm) 3Q25A 4Q25E 2025E Total D&C $519 $480 – $530 $2,055 – $2,165 Haynesville 59% ~47% ~54% Northeast Appalachia 19% ~29% ~21% Southwest Appalachia 22% ~24% ~25% Other Capex (Field)(1) $67 $80 – $100 $290 – $310 Other Capex (Corporate)(2) $49 $45 – $55 $180 – $200 Total Base Capital Expenditures $635 $605 – $685 $2,525 – $2,675 Productive Capacity Program $100 ~$80 up to $250 Total Capital Expenditures $735 $685 – $765 $2,775 – $2,925 Land and Leasehold Acquisitions ($mm) 3Q25A 4Q25E 2025E Land and Leasehold $69 ~$105 ~$175 Operating Costs (per Mcfe of Projected Production) 3Q25A 2025E Production Expense $0.25 $0.23 – $0.28 Gathering, Processing and Transportation (GP&T) $0.97 $0.96 – $1.11 GP&T Expense $0.90 $0.90 – $1.00 GP&T FMV Liability (3) $0.07 $0.06 – $0.11 Severance and Ad Valorem Taxes $0.07 $0.08 – $0.10 General and Administrative $0.07 $0.07 – $0.09 Depreciation, Depletion and Amortization $1.10 $1.05 – $1.15 Corporate Expenses ($mm) 3Q25A 2025E Interest Expense $57 $225 – $250 Cash Income Tax Ranges at Flat Prices $0 $3.50 $50 – $100 $4.00 $100 – $150 $4.50 $150 – $200 Basis Differentials (excluding hedges) 3Q25A 2025E Estimated (E) Basis Deduct to NYMEX Prices, based on 10/22/2025 Strip Prices: Natural Gas ($/Mcf) ($0.49) ($0.30) – ($0.45) Oil ($/bbl) ($11.43) ($10.00) – ($12.00) NGL (% of WTI) 33% 35% – 45% Bold / Italicized = updated guidance range 3Q 2025 Earnings (1) Other Capex (Field) includes Leasehold and Workover expenses (2) Other Capex (Corporate) includes PP&E, Capitalized G&A and Interest expenses (3) GP&T fair market liability related to the amortization of the $175mm – $225mm net liability for out-of-market contracts assumed in the Southwestern merger
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3Q25 EXE Business Unit Results 20 Haynesville NE Appalachia SW Appalachia Production (MMcfe/d) 3,206 2,556 1,571 Production Expense ($/Mcfe) $0.27 $0.18 $0.32 Differential to NYMEX ($/Mcf) $(0.27) $(0.78) $(0.43) GP&T ($/Mcfe) $0.72 $0.85 $1.36 Rigs 7 2 2 Spuds (by zone) Haynesville 9 Bossier 8 Lower 8 Upper(1) 5 Marcellus 11 Utica 0 TILs (by zone) Haynesville 10 Bossier 15 Lower 13 Upper(1) 7 Marcellus 8 Utica 4 D&C Capex ($mm) $355 $150 $114 Total Capital ($mm) $416 $175 $144 3Q 2025 Earnings (1) NE Appalachia Upper Marcellus category is inclusive of hybrid wells
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Haynesville, Northeast and Southwest Appalachia Sales Points 21 Haynesville Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current CGML ($0.28) CGML ($0.25) TGT ($0.25) TGT ($0.22) TETCO WLA ($0.09) TETCO WLA ($0.11) 9% of NYMEX 7% of NYMEX HAYNESVILLE TOTAL PRODUCTION(2) CGML/TGT 35% TETCO WLA/NYMEX/Other 65% NE App Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current TETCO M3 +$0.05 TETCO M3 ($0.07) Leidy ($0.76) Leidy ($0.78) Eastern Gas ($0.82) Eastern Gas ($0.85) TGP 300L ($0.83) TGP 300L ($0.88) 20% of NYMEX 14% of NYMEX NE APP TOTAL PRODUCTION(2) In Basin 55% Out of Basin 45% Leidy 30% TETCO M3 25% Eastern Gas 20% NYMEX 20% TGP 300L 5% SW App Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current TCO ($0.67) TCO ($0.65) TrunklineZ1A ($0.28) TrunklineZ1A ($0.28) CGML ($0.28) CGML ($0.25) CG Onshore ($0.13) CG Onshore ($0.08) Rex Zone 3 ($0.18) Rex Zone 3 ($0.25) 15% of NYMEX 10% of NYMEX SW APP TOTAL PRODUCTION(2) TCO 40% TrunklineZ1A 25% CGML 15% CG Onshore 10% Rex Zone 3 10% 3Q 2025 Earnings (1) Historical prices based on NYMEX contract settlement for January 2023 – December 2024; current prices based on NYMEX settled and future prices for January 2025 – December 2026, strip as of 10/22/2025 (2) Percentage of production based on 2025 Production Guidance
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14.9 14.9 14.9 14.9 4.2 6.2 16.7 16.4 2024 2025 2026 2027 – 2029 2030+ Online LNG Under Construction LNG FERC and DOE Approved LNG ▪ EXE portfolio uniquely positioned to meet growing LNG demand ▪ Currently selling ~2 Bcf/d to LNG export facilities ▪ ~2.5 Bcf/d of EXE deliverability to LNG corridor Being LNG Ready Will Create Meaningful Value and Enhance Returns 3Q 2025 Earnings22 ~32 Bcf/d of total LNG export capacity expected by 2029 Growing Exports Expected to be Significant to U.S. Gas Demand (U.S. LNG Capacity, Bcf/d)(1) 2025: Corpus Christi Plaquemines Sempra – Costa Azul 2026: Corpus Christi Golden Pass 2027+: Calcasieu Pass 2 Golden Pass Rio Grande Sempra – Port Arthur Woodside Calcasieu Pass Cameron Corpus Christi Cove Point Elba Island Freeport Kenai New Fortress Sabine Pass Port Arthur Sabine Pass Saguaro Sempra – Cameron Texas Brownsville Woodside Commonwealth Delfin LNG Eagle Freeport Gulf Lake Charles Magnolia (1) Volumes per FERC; Inservice estimations from EIA and project websites
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~$400 ~$400 ~$500 ~$500 ~$600 ~$100 ~$100 Initial Synergy Target @ Announcement Additional Synergies Identified @ Close Synergy Target @ Close Synergy Delivery Outperformance Total Synergies from Merger Merger Synergies Exceeded Expectations 23 • Corporate and regional costs • D&C cost savings • Other operating and capital • ~$250mm by 2025 and $400mm by 2026 • Haynesville sand mine cost savings • Completion design optimization • Financing cost savings • Accelerated to ~$400mm in 2025 and ~$500mm in 2026 • Continued optimization of Haynesville drilling program • Incremental non-comp G&A realization around IT spend • Increased Haynesville sand mine utilization • Optimization of Haynesville facility design • Accelerated to ~$500mm in 2025 and ~$600mm in 2026 ~50% improvement in synergies compared to announcement 3Q 2025 Earnings
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Inaugural report highlights our commitments and progress ▪ Achieved 100% Responsibly Sourced Gas (RSG) across portfolio (MiQ and EO100 ) ▪ Serious Incident and Fatality (SIF) program adoption for proactive safety prevention ▪ Net zero Scope 1 and 2 GHG emissions target by 2035 ▪ Employee and executive compensation tied to sustainability performance ▪ Consistent stakeholder engagement through materiality assessment, local and virtual meetings and community investment ▪ Partnering with local government agencies and nonprofits for freshwater and habitat conservation program 2024 Sustainability Performance Highlights 3Q 2025 Earnings24 Transparent and measurable disclosures: 0.13 Combined TRIR 2.6 Scope 1 and 2 Greenhouse gas emissions intensity (1) 12.2 million bbls recycled produced water 0.02% Scope 1 Methane emissions intensity (2) 100% produced water recycled in NE App Download the report at expandenergy.com/sustainability (1) Calculated as metric tons CO2e / gross operated Mboe produced (2) Calculated as volume methane emissions / volume gross natural gas produced
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NATURAL GAS ESTIMATED NYMEX GAS SETTLEMENT ($mm) Date SWAPS COSTLESS COLLARS THREE-WAY COLLARS Date $2.00 NYMEX $3.00 NYMEX $4.00 NYMEX $5.00 NYMEXVolume Bcf Price $/Mcf Volume Bcf Bought Put $/Mcf Sold Call $/Mcf Volume Bcf Bought Put $/Mcf Sold Call $/Mcf Sold Put $/Mcf 1Q 2025 103.9 3.40 182.4 3.42 4.65 39.6 3.66 5.88 2.59 1Q 2025 (25) (25) (25) (25) 2Q 2025 103.3 3.46 221.0 3.31 4.34 40.0 3.66 5.88 2.59 2Q 2025 30 30 30 30 3Q 2025 101.0 3.54 222.2 3.31 4.35 40.5 3.66 5.88 2.59 3Q 2025 135 135 135 135 4Q 2025 81.7 3.61 240.6 3.37 4.70 40.5 3.66 5.88 2.59 4Q 2025 438 185 32 (89) FY 2025 389.9 $3.49 866.2 $3.35 $4.51 160.6 $3.66 $5.88 $2.59 FY 2025 $578 $325 $172 $51 1Q 2026 80.8 3.94 295.4 3.45 5.06 – – – – 1Q 2026 584 208 (5) (165) 2Q 2026 90.8 3.92 213.9 3.43 4.77 – – – – 2Q 2026 481 176 (7) (177) 3Q 2026 82.6 3.93 194.8 3.47 4.88 – – – – 3Q 2026 446 168 (9) (143) 4Q 2026 85.7 3.99 144.2 3.52 5.01 – – – – 4Q 2026 389 159 (1) (117) FY 2026 339.8 $3.95 839.3 $3.46 $4.94 – – – – FY 2026 $1,900 $711 ($22) ($602) 1Q 2027 31.5 3.93 131.2 3.70 5.07 – – – – 1Q 2027 284 121 (1) (55) 2Q 2027 31.9 3.93 63.0 3.61 4.59 – – – – 2Q 2027 163 68 (2) (61) 3Q 2027 32.2 3.93 20.5 3.70 4.38 – – – – 3Q 2027 97 44 (2) (47) 4Q 2027 4.6 3.97 18.6 3.70 4.33 4Q 2027 41 17 (0) (17) FY 2027 100.2 3.93 233.3 $3.67 $4.90 – – – – FY 2027 $585 $250 ($5) ($180) Reducing Risk, Protecting Returns Through Hedge Program 25 3Q 2025 Earnings Hedge position as of 10/22/2025
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NATURAL GAS LIQUIDS ESTIMATED NGL SETTLEMENT ($mm) Date C2 SWAPS C3 SWAPS C4 SWAPS C5 SWAPS Date $0.25 $0.50 $1.00 $1.50 Volume MBbl Price $/gal Volume MBbl Price $/gal Volume MBbl Price $/gal Volume MBbl Price $/gal 1Q 2025 900 0.25 603 0.73 135 0.84 203 1.35 1Q 2025 (8) (8) (8) (8) 2Q 2025 910 0.25 546 0.74 137 0.84 205 1.35 2Q 2025 (1) (1) (1) (1) 3Q 2025 920 0.25 552 0.74 138 0.84 207 1.35 3Q 2025 2 2 2 2 4Q 2025 920 0.25 552 0.74 138 0.84 207 1.35 4Q 2025 17 4 (21) (46) FY 2025 3,650 $0.25 2,253 $0.74 548 $0.84 821 $1.35 FY 2025 $10 ($3) ($28) ($53) FY 2026 – – – – – – – – FY 2026 – – – – Reducing Risk, Protecting Returns Through Hedge Program 26 3Q 2025 Earnings Hedge position as of 10/22/2025
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Reducing Risk, Protecting Returns Through Hedge Program 27 CRUDE OIL ESTIMATED NYMEX WTI SETTLEMENT ($mm) Date SWAPS COSTLESS COLLARS THREE-WAY COLLARS Date $60.00 WTI $70.00 WTI $80.00 WTI $90.00 WTIVolume MBbl Price $/Bbl Volume MBbl Bought Put $/Bbl Sold Call $/Bbl Volume MBbl Bought Put $/Bbl Sold Call $/Bbl Sold Put $/Bbl 1Q 2025 41 77.66 – – – 270 70.00 94.67 60.00 1Q 2025 0 0 0 0 2Q 2025 – – – – – 364 70.00 94.63 60.00 2Q 2025 2 2 2 2 3Q 2025 – – – – – 368 70.00 94.63 60.00 3Q 2025 2 2 2 2 4Q 2025 – – – – – 322 65.71 86.81 55.71 4Q 2025 2 1 1 (0) FY 2025 41 $77.66 – – – 1,324 $68.96 $92.73 $58.96 FY 2025 $6 $5 $5 $4 1Q 2026 – – – – – 225 70.00 83.32 60.00 1Q 2026 2 0 0 (2) FY 2026 – – – – – 225 $70.00 $83.32 $60.00 FY 2026 $2 $0 $0 ($2) 3Q 2025 Earnings Hedge position as of 10/22/2025
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Hedged Financial Basis 28 HAYNESVILLE NORTHEAST APPALACHIA Date CGT MAINLINE TETCO WLA TGT Z1 TETCO M3 TGP Z4 300L LEIDY EASTERN GAS Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf Volume Bcf Avg. Price $/Mcf 1Q 2025 5.4 (0.21) – – 35.3 (0.24) 15.8 1.03 0.9 (0.75) 15.8 (0.66) 2.3 (0.64) 2Q 2025 0.9 (0.23) – – 28.4 (0.24) 16.1 (0.86) – – 28.2 (1.00) 3.8 (0.79) 3Q 2025 0.9 (0.23) – – 28.8 (0.24) 19.3 (0.86) – – 28.5 (1.00) 6.9 (0.89) 4Q 2025 0.3 (0.23) – – 19.8 (0.23) 20.7 0.36 – – 23.3 (0.83) 9.3 (0.78) FY 2025 7.5 ($0.22) – – 112.3 ($0.23) 71.8 ($0.09) 0.9 ($0.75) 95.8 ($0.90) 22.3 ($0.80) 1Q 2026 – – 1.4 0.11 14.9 (0.22) 35.3 0.46 – – 23.0 (0.73) 13.5 (0.86) 2Q 2026 – – 1.4 0.11 – – 40.7 (0.70) – – 23.0 (1.11) 18.0 (1.07) 3Q 2026 – – 1.4 0.11 – – 41.2 (0.70) – – 23.2 (1.11) 18.2 (1.07) 4Q 2026 – – 1.4 0.11 – – 28.2 (0.25) – – 17.0 (0.94) 12.8 (1.00) FY 2026 – – 5.5 $0.11 14.9 ($0.22) 145.4 ($0.33) – – 86.1 ($0.97) 62.5 ($1.01) 1Q 2027 – – – – – – 6.7 0.98 – – 10.8 (0.76) 4.5 (0.88) 3Q 2025 Earnings Hedge position as of 10/22/2025
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As a supplement to the financial results prepared in accordance with U.S. GAAP, Expand Energy’s quarterly earnings presentations contain certain financial measures that are not prepared or presented in accordance with U.S. GAAP. These non-GAAP financial measures include Adjusted EBITDAX, Free Cash Flow, Adjusted Free Cash Flow, Net Debt and Total Capitalization. A reconciliation of each financial measure to its most directly comparable GAAP financial measure is included in the following tables. Management believes these adjusted financial measures are a meaningful adjunct to earnings and cash flows calculated in accordance with GAAP because (a) management uses these financial measures to evaluate the company’s trends and performance, (b) these financial measures are comparable to estimates provided by securities analysts, and (c) items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Due to the forward-looking nature of projected Adjusted EBITDAX, projected Free Cash Flow and projected Adjusted Free Cash Flow used herein, management cannot reliably predict certain of the necessary components of the most directly comparable forward- looking GAAP measures. Accordingly, the Company is unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward- looking GAAP financial measures without unreasonable effort. Amounts excluded from these non-GAAP measures in future periods could be significant. Expand Energy’s definitions of each non-GAAP measure presented herein are provided below. Because not all companies or securities analysts use identical calculations, Expand Energy’s non-GAAP measures may not be comparable to similarly titled measures of other companies or securities analysts. Adjusted EBITDAX: Adjusted EBITDAX is defined as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization expense, exploration expense, unrealized (gains) losses on natural gas, oil and NGL derivatives, separation and other termination costs, (gains) losses on sales of assets, and certain items management believes affect the comparability of operating results. Adjusted EBITDAX is presented as it provides investors an indication of the company's ability to internally fund exploration and development activities and service or incur debt. Adjusted EBITDAX should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by (used in) operating activities as presented in accordance with GAAP. Free Cash Flow: Free Cash Flow is defined as net cash provided by (used in) operating activities less cash capital expenditures. Free Cash Flow is a liquidity measure that provides investors additional information regarding the company’s ability to service or incur debt and return cash to shareholders. Free Cash Flow should not be considered an alternative to, or more meaningful than, net cash provided by (used in) operating activities, or any other measure of liquidity presented in accordance with GAAP. Adjusted Free Cash Flow: Adjusted Free Cash Flow is defined as net cash provided by (used in) operating activities less cash capital expenditures and cash contributions to investments, adjusted to exclude certain items management believes affect the comparability of operating results. Adjusted Free Cash Flow is a liquidity measure that provides investors additional information regarding the company’s ability to service or incur debt and return cash to shareholders. Adjusted Free Cash Flow should not be considered an alternative to, or more meaningful than, net cash provided by (used in) operating activities, or any other measure of liquidity presented in accordance with GAAP. Net Debt: Net Debt is defined as GAAP total debt excluding premiums, discounts, and deferred issuance costs less cash and cash equivalents. Net Debt is useful to investors as a widely understood measure of liquidity and leverage, but this measure should not be considered as an alternative to, or more meaningful than, total debt presented in accordance with GAAP. Total Capitalization: Total Capitalization is defined as Net Debt plus total stockholders’ equity and is used in the Net Debt to Capitalization ratio. Non-GAAP Financial Measures 29 3Q 2025 Earnings
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30 Three Months Ended September 30, 2025 Three Months Ended June 30, 2025 Three Months Ended March 31, 2025 Three Months Ended December 31, 2024 Trailing Twelve Months Three Months Ended September 30, 2024 ($ in millions) Net Income (Loss) (GAAP) $ 547 $ 968 $ (249) $ (399) $ 867 $ (114) Adjustments: Interest expense 57 60 59 64 240 20 Income tax expense (benefit) 139 260 (70) (22) 307 (44) Depreciation, depletion and amortization 741 769 711 647 2,868 335 Exploration 3 20 7 3 33 2 Unrealized (gains) losses on natural gas, oil and NGL derivatives (309) (842) 969 490 308 160 Separation and other termination costs 5 – – – 5 – (Gains) losses on sales of assets 1 (4) – (2) (5) (2) Other operating expense (income), net(1) (40) 32 26 267 285 23 (Gains) losses on purchases, exchanges or extinguishments of debt (1) (3) – (1) (5) – Contract amortization (47) (72) (52) (57) (228) – Other (14) (12) (6) (26) (58) (15) Adjusted EBITDAX (Non-GAAP) $ 1,082 $ 1,176 $ 1,395 $ 964 $ 4,617 $ 365 Three Months Ended September 30, 2025 Three Months Ended September 30, 2024 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 1, 201 $ 422 Cash capital expenditures (775) (298) Free Cash Flow (Non-GAAP) 426 124 Cash paid for merger expenses 2 – Cash contributions to investments (5) (26) Adjusted Free Cash Flow (Non-GAAP) $ 423 $ 98 Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (Unaudited) Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Unaudited) 3Q 2025 Earnings (1) Includes an adjustment for costs incurred related to the Southwestern merger
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31 Reconciliation of Total Debt to Total Capitalization (Unaudited) September 30, 2025 ($ in millions) Total Debt (GAAP) $ 5,010 Premiums, discounts and issuance costs on debt 15 Principal Amount of Debt 5,025 Cash and cash equivalents (613) Net Debt (Non-GAAP) 4,412 Total stockholders’ equity 18,150 Total Capitalization (Non-GAAP) $ 22,562 Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDAX (Unaudited) Three Months Ended September 30, 2025 Three Months Ended September 30, 2024 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 1,201 $ 422 Changes in assets and liabilities (72) (85) Interest expense 57 20 Current income tax benefit (47) – Share-based compensation (12) (10) Other (45) 18 Adjusted EBITDAX (Non-GAAP) $ 1,082 $ 365 3Q 2025 Earnings