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4Q & FY 2025 Earnings FEBRUARY 17, 2026
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This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Sect ion 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to armed conflict between Russia and Ukraine, instability in the Middle East and Venezuela and cha nges in China-Taiwan relations, along with the effects of the current global economic environment, and the impact of each on our bu siness, financial condition, results of operations and cash flows, actions by, or disputes among or between, members of OPEC+ and other foreign oil -exporting countries, market factors, market prices, our ability to meet debt service requirements, our ability to continue to pay cash dividends, the amount and timing of any cash dividends and our sustainability initiatives. Forward-looking and other statements in this presentation regarding our environmen tal, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the 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 between Russia and Ukraine, instability in the Middle East and Venezuela and changes in China -Taiwan relations, along with the effects of the current global economic environment, on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and on U.S. and global financial markets; ▪ our inability to access the capital markets on favorable terms; ▪ the limitations on our financial flexibility due to our level of indebtedness and restrictive covenants from our indebtedness ; ▪ challenges with employee recruitment and retention and an increasingly competitive labor market; ▪ risks related to acquisitions or dispositions, or potential acquisitions or dispositions; ▪ security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our 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 sustainability certifications, goals and commitments; ▪ environmental and sustainability legislation and regulatory initiatives, including those addressing the impact of climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal; ▪ federal and state tax proposals affecting our industry; ▪ risks related to an annual limitation on the utilization of our tax attributes, which was triggered upon the completion of ou r merger with Southwestern Energy Company (“the Southwestern Merger”), as well as trading in our common stock, additional issuan ce 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 4Q & FY 2025 Earnings 2
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Operational and Financial Highlights 4Q & FY 2025 Earnings (1) Adjusted EBITDAX is a non-GAAP financial measure, see Appendix for more information and reconciliation to the most directly comp arable GAAP financial measure (2) Net debt is a non-GAAP financial measure, see Appendix for more information 3 Largest domestic natural gas producer: ~7.4 Bcfe/d Flexed productive capacity for 4Q25: ~$1.4bn of Adjusted EBITDAX (1) ~$730mm of capex ~$1.2bn gross debt reduction since merger close Multi-year deleveraging effort; expect at least $1bn net debt reduction in 2026(2) Improved Haynesville breakeven by ~15% Haynesville capital efficiency improvements yielding <$2.75 breakeven 2026 outlook: ~7.5 Bcfe/d for ~$2.85bn capex Inclusive of ~$75mm Western Haynesville appraisal spend Returned ~$865mm to shareholders in 2025 Meaningful shareholder returns continue alongside robust deleveraging efforts Enhancing our multi-decade inventory base Deep inventory supporting returns for decades (20+ years)
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2026 Outlook 4Q & FY 2025 EARNINGS
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~$1,125 $2,625 ~$2,850 ~$75 ~$525 ~$575 ~$400 ~$150 Haynesville Northeast App Southwest App Other Field Corporate 2026E Capex 2026 Capital Outlook 5 ~$2.85bn • Leasehold • Workover • PP&E • G&A • Capitalized interest Delivers ~7.5 Bcfe/d in 2026 2026 Capital Expenditures (Implied Midpoints of 2026 Guidance, $mm) 4Q & FY 2025 Earnings ▪ ~$2.85bn FY26 capex inclusive of ~$75mm Western Haynesville appraisal spend ▪ Continued operational performance and productivity improvements driving down reinvestment rate ▪ Retain flexibility to adjust should fundamentals shift mid-cycle price ~$225mm improvement to ~7.5 Bcfe/d maintenance program since merger close • Growth D&C
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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 $2.5 7.00 $2.6 7.25 $2.7 7.50 $2.8 7.75 $2.9 8.00 $3.1 8.25 $3.2 Optimizing Maintenance Production to Maximize Free Cash Flow (1) 4Q & FY 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; growth capital is not included; utilizes current cost assumptions as of February 2026 6 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 Illustrative Annual FCF (2) at Various Mid-cycle Prices, Maintenance Production and Capital
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Attractive, Connected Portfolio 4Q & FY 2025 EARNINGS
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Scale: Largest natural gas producer in North America with ~2.0mm net acres, ~7.5 Bcfe/d in 2026 Flexibility: Highly complementary asset base offers capital allocation flexibility Growth: Differentiated ability to accretively grow volumes (when supply is needed) Attractive, Connected Portfolio 4Q & FY 2025 Earnings Net acres and gross locations as of 12/31/2025 (1) >5,000 gross locations divided by ~225 annual TILs 8 Location: Geographically diverse portfolio colocated with highest growth demand centers Longevity: Deep inventory supporting returns for decades (20+ years (1) ) Connectivity: Inter- connected transportation portfolio links assets to premium markets Superior Portfolio Characteristics NORTHEAST APPALACHIA ~704,000 net acres >1,500 gross locations FY26E Prod: ~2,675 MMcfe/d HAYNESVILLE ~745,000 net acres >2,000 gross locations FY26E Prod: ~3,200 MMcfe/d SOUTHWEST APPALACHIA ~592,000 net acres >1,500 gross locations FY26E Prod: ~1,625 MMcfe/d
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$1.80 $2.04 $2.05 $2.97 $3.52 EXE Peer 1 Peer 2 Peer 3 Peer 4 $1.45 $1.89 $1.90 $2.20 $2.30 Peer 1 Peer 2 EXE Peer 3 Peer 4 Southwest Appalachia(2) $2.20 $2.41 $2.76 $3.23 $3.37 $3.47 EXE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Haynesville Consistently Outperforming Peers (1) Data source: Enverus; LL weighted historical average, 2021 – 2025 TILs. Haynesville Peers: Aethon, Apex, BP, CRK, TGNR. NE App Peers: CTRA, EQT, NFG, Repsol. SW App Peers: AR, CNX, EQT, RRC. (2) SW App production numbers calculated using a 20:1 ratio for oil and 7:1 ratio for NGLs 9 Capital Efficiency Leader Across the Premier Gas Basins ($/12-month Mcfe) (1) 4Q & FY 2025 Earnings Northeast Appalachia
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EXE Acreage 3,193 3,000 ~ 3,175 ~ 3,200 4Q25 FY25 1Q26 FY26 ▪ Moving beyond synergy capture to operational and high-performance execution; 2025 was the company’s fastest year ever for drilling feet per day ▪ Inventory upside and developmental optionality introduced with Western Haynesville leasehold additions in 2025 ▪ Midstream infrastructure and inventory depth provides growth flexibility as LNG demand increases ▪ Lowering asset breakeven through vertical integration (sand mine, produced water infrastructure and EDC (1) rigs) Haynesville: Premium Markets with Scalable Growth 10 4Q & FY 2025 Earnings (1) Expand Drilling Company 2026 Guidance2025 Actuals Haynesville Production (MMcfe/d) 4Q25 FY25 1Q26 FY26 Rig Count 7 7 7 7 Crew Count 3 3.5 3 3 Net Acreage ~745,000 Avg. WI / NRI ~92% / ~73% L O U I S I A N A T E X A S
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806 812 783 ~835 ~900 2022 2023 2024 2025E 2026E Productivity Improving Through Time (12 mo. Mcfe/ft.) ▪ Optimization of development plan and completion design improving productivity through time ▪ Average EXE well productivity (1) was ~50% greater than basin average 2022 – 2025; expect trend to continue ▪ ~20% of FY25 TILs have 12-month cum. >1 Bcfe/1,000 ft.; expect >30% of FY26 TILs >1 Bcfe/1,000 ft. Haynesville Capital Efficiency Improvements Yielding <$2.75 Breakeven 4Q & FY 2025 Earnings Annual asset-level breakeven excludes corporate items (1) 12-month cumulative Mcfe/ft.; peer data sourced from Enverus (2) Historical cost per foot is inclusive of both Legacy CHK and Legacy SWN actuals (3) Data reflects proposed non-operated capex spend 11 ~11% increase in well performance since 2022 $1,657 $1,847 $1,573 ~$1,370 ~$1,340 2022 2023 2024 2025E 2026E Demonstrating Continued Capital Improvements ($/ft.) (2) ~19% reduction in well costs since 2022 ▪ Drilling improvements, deflation capture and company- owned sand mine driving significant capital cost savings ▪ 2026 non-operated AFEs show average EXE capex/ft. ~15% lower than peers (3) despite ~15% higher completion intensity ▪ Synergies driving production expense down ~20% from original FY25 guidance Basin-leading well performance with >20 years of durable inventory
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~420 ~750 ~1,000 ~1,400 > 2,000 ~700 ~1,090 ~1,440 ~1,770 > 2,000 $2.50 $2.75 $3.00 $3.50 $4.00+ HSVL FY24 Earnings (02.25) HSVL FY25 Earnings (02.26) ▪ ~22 years of derisked inventory, the deepest and highest quality in basin ▪ Operational efficiencies and lateral extensions reducing breakevens ▪ Significantly increasing portfolio competitiveness by adding ~5 years of inventory to <$3.50 breakeven bucket ▪ Recent update includes ~200 Western Haynesville locations (1) with potential for meaningful upside Haynesville Basin-Leading Breakevens 4Q & FY 2025 Earnings12 Average inventory breakeven has improved by ~15% since merger close (Avg. LL: ~10,000′) (1) Western Haynesville locations currently included in $4.00+ bucket
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2,610 2,624 ~ 2,800 ~ 2,675 4Q25 FY25 1Q26 FY26 Northeast Appalachia: Low Breakeven, Cash Flow Machine 13 4Q & FY 2025 Earnings Net Acreage ~704,000 Avg. WI / NRI ~58% / ~49% EXE Acreage N E W Y O R K P E N N S Y L V A N I A ▪ DTIL activation, operational efficiencies and enhanced completion designs position company to maintain production with low rig count ▪ Gathering system debottlenecking leads to improved deliverability and reliability ▪ Foundational cash flow and low reinvestment rate underpins base dividend 2026 Guidance2025 Actuals Northeast Appalachia Production (MMcfe/d) 4Q25 FY25 1Q26 FY26 Rig Count 3 2 – 3 3 3 Crew Count 2 2 2 2
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1,597 1,559 ~ 1,475 ~ 1,625 4Q25 FY25 1Q26 FY26 2026 Guidance2025 Actuals Southwest Appalachia Production (MMcfe/d) 4Q25 FY25 1Q26 FY26 Rig Count 2 2 2 1 – 2 Crew Count 1 2 2 1 – 2 Net Acreage ~592,000 Avg. WI / NRI ~88% / ~72% 14 O H I O P E N N S Y L V A N I A W E S T V I R G I N I A Southwest Appalachia: Liquids Exposure and Upside Potential 14 4Q & FY 2025 Earnings ~65% Gas ~30% NGLs ~5% Oil ▪ Asset delivers attractive liquids exposure through significant NGL and condensate production ▪ Strategically positioned to support long-term partnership opportunities with industrial, utility, and power generation customers ▪ Acreage landscape offers valuable opportunities for lateral length additions and inventory growth EXE Acreage
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~880 ~1,180 ~1,300 ~1,420 >1,500 $2.50 $2.75 $3.00 $3.50 $4.00+ ~600 ~890 ~1,200 ~1,360 >1,500 $2.50 $2.75 $3.00 $3.50 $4.00+ 20+ Years of Appalachia Breakeven Inventory Below $3.50/Mcf 4Q & FY 2025 Earnings15 Northeast Appalachia (Avg. LL: ~13,250′) Southwest Appalachia (Avg. LL: ~14,000′) ▪ Breakevens improved ~6% driven by longer laterals and improved capital efficiency ▪ Drilling efficiency gains lowered cost/ft; 2025 set a record at 1,861 ft/d (+18% vs. 2024) ▪ Enhanced wellbore trajectories driving longer laterals and higher completable footage ▪ Added ~1.5mm feet of completable lateral via organic leasing and bolt-ons in 2025 ▪ ~55% of FY26 and FY27 development program includes laterals exceeding 20,000′, with the longest surpassing 27,000′ – a record for both the basin and U.S. land ▪ Potential to unlock meaningful upside by applying proven Ohio Utica development practices to West Virginia Utica
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Marketing & Commercial: Answering the Call for Growing Demand 4Q & FY 2025 EARNINGS
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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 Lower Carbon Energy to Growing Markets 4Q & FY 2025 Earnings 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 17 Expand has differentiated access to growing natural gas demand 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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GULF COAST 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 ▪ Pipeline capacity from associated gas basins, expect to compete for supply with growing demand in Texas and Mexico • Additional 8 Bcf/d demand growth in Texas • Mexico exports providing 2 Bcf/d of incremental demand growth EXE PORTFOLIO ▪ October 2025: NG3 in-service increased EXE’s pipeline capacity and connectivity to Gulf Coast demand ▪ Portfolio of transport capacity delivers direct access and optionality to premium markets; ~2.5 Bcf/d capacity to Gillis and ~2 Bcf/d capacity to Perryville Positioned to Supply an Increasingly Tight Gulf Coast Market 4Q & FY 2025 Earnings EXE estimates based on EIA data, FERC filings and public statements Existing facilities include Sabine Pass, Corpus Christi T1-3, Cameron T1-3, Freeport T1-3, Calcasieu Pass 1-9, Plaquemines; 2026 facilities include Corpus Christi 3 and Golden Pass; 2027 facilities include Port Arthur T1 -2, Rio Grande, Calcasieu Pass 2; 2028+ facilities include Louisiana LNG, CP2, Magnolia, Cameron T4, Freeport T4, Delfin, Texas LNG, Commonwealth, Port Arthur T3-4 18 EXE Haynesville has access to tangible LNG, power and industrial demand 0 10 20 30 Online in 2028+ Online in 2027 Online in 2026 2025 Expected LNG Export Capacity (Bcf) Gillis Perryville Katy Agua Dulce 4.4 Bcf/d POWER/INDUSTRIAL DEMAND +2.3 Bcf/d 2025 Demand Bcf/d 2030 Demand Gain Bcf/d
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Expanding the Value of Natural Gas 4Q & FY 2025 Earnings 19 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 • Reach Premium Markets: Executed additional term sales +350,000 MMbtu/d to Gulf Coast end-users during the fourth quarter • Manage Volatility: Added new storage capacity, now totaling 5 bcf, and incremental pipeline capacity, enhancing market connectivity and optionality • Facilitate and Capture New Demand: Supplying microgrid solutions in Appalachia with flexible volume contracts
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Resilient Financial Foundation 4Q & FY 2025 EARNINGS
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Investment Grade Balance Sheet Supports Through-Cycle Value Creation 4Q & FY 2025 Earnings 21 (1) As of 1/30/2026 ▪ Current balance sheet is strong, however additional deleveraging creates more capacity at cycle-lows ▪ Deleveraging should occur at favorable prices facilitating more consistent shareholder returns through-cycle ▪ Callable debt provides efficient pathway to debt reduction – 2029 maturities all become callable at par in 2026 Debt Maturity Profile (BBB-, Baa3, BBB-) ($mm)(1) $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 ~6.10% ~5.17% 5.375% 4.75% 5.70% Callable debt EXE RBL Capacity
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▪ Annual Base Dividend • Remains priority and is paid through-cycle • $2.30/share annually • 4Q25 DPS of $0.575/sh to be paid in March ▪ Net Debt Reduction • Continued debt reduction improves through-cycle balance sheet capacity • Allocating at least $1bn to net debt reduction in 2026 • Gross debt reduction through callable notes ▪ Additional Shareholder Returns • Anticipate opportunistic buybacks to supplement additional debt reduction Balancing Debt Reduction and Shareholder Returns 4Q & FY 2025 Earnings 22 Retaining flexibility to respond to market conditions Historical Shareholder Returns ($mm) $256 $302 $370 $554 $2.30/ sh $956 $185 $18 $211 $1,073 $355 $100 $591 $661 >$1bn 2021 2022 2023 2024 2025 2026E Gross Debt Reduction Share Repurchases Variable Dividend Base Dividend $120 $2,285 $842 $979 $1,526 Increased focus on debt reduction since merger close Buybacks or Additional Debt Reduction
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$5.10 $3.15 $3.57 $4.03 $4.25 $3.27 $3.56 $3.98 $4.81 $4.39 $4.46 $4.72 $4.81 $4.10 $3.95 $4.00 $3.62 $3.59 $3.64 $3.77 $3.86 $3.69 $3.75 $3.76 1Q26 2Q26 3Q26 4Q26 1Q27 2Q27 3Q27 4Q27 Hedge Position Preserves Upside and Provides Downside Protection 4Q & FY 2025 Earnings (1) As of 2/11/2026 23 376 305 277 230 163 95 53 23 46 132 168 163 186 175 94 28 1Q26 2Q26 3Q26 4Q26 1Q27 2Q27 3Q27 4Q27 Hedged Natural Gas Volumes Current Hedge Book Supports Near-Term Realizations and Preserves Upside Ceiling and Floor (1) ($/MMbtu) Realized Price Strip Added since 3Q Earnings (Bcf) Last Public Disclosure (Bcf) 66% hedged in 2026
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Expanding Returns, Expanding Opportunities 4Q & FY 2025 Earnings 24 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
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Appendix 4Q & FY 2025 EARNINGS
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Management’s Guidance as of February 17, 2026 4Q & FY 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) Land and Leasehold 4Q25 actuals reflect close of previously announced Western Haynesville transaction (4) GP&T fair market liability related to the amortization of the $150mm – $200mm net liability for out-of-market contracts assumed in the Southwestern merger 26 Production (MMcfe/d) 4Q25A 1Q26E 2026E Total Production 7,400 7,400 – 7,500 7,400 – 7,600 Haynesville 3,193 ~3,175 ~3,200 Northeast Appalachia 2,610 ~2,800 ~2,675 Southwest Appalachia 1,597 ~1,475 ~1,625 Capital Expenditures ($mm) 4Q25A 1Q26E 2026E Total D&C $578 $575 – $625 $2,250 – $2,350 Haynesville 53% ~53% ~52% Northeast Appalachia 27% ~20% ~23% Southwest Appalachia 20% ~27% ~25% Other Capex (Field)(1) $105 $100 – $125 $350 – $450 Other Capex (Corporate)(2) $45 $40 ~$150 Total Capital Expenditures $728 $715 – $790 $2,750 – $2,950 Land and Leasehold Acquisitions ($mm) 4Q25A 1Q26E 2026E Land and Leasehold (3) $126 $0 $0 Operating Costs (per Mcfe of Projected Production) 4Q25A 2026E Production Expense $0.25 $0.23 – $0.28 Gathering, Processing and Transportation (GP&T) $0.99 $1.01 – $1.13 GP&T Expense $0.94 $0.95 – $1.05 GP&T FMV Liability (4) $0.05 $0.06 – $0.08 Severance and Ad Valorem Taxes $0.07 $0.08 – $0.10 General and Administrative $0.07 $0.07 – $0.10 Depreciation, Depletion and Amortization $1.11 $1.10 – $1.15 Corporate Expenses ($mm) 4Q25A 2026E Interest Expense $59 $225 – $250 Cash Income Tax Ranges at Flat Prices $0 $3.50 $0 $4.00 $0 – $25 $4.50 $25 – $50 Basis Differentials (excluding hedges) 4Q25A 2026E Estimated (E) Basis Deduct to NYMEX Prices, based on 2/11/2026 Strip Prices: Natural Gas ($/Mcf) ($0.27) ($0.30) – ($0.40) Oil ($/bbl) ($11.17) ($9.00) – ($11.00) NGL (% of WTI) 40% 30% – 38%
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4Q25 EXE Business Unit Results 4Q & FY 2025 Earnings (1) NE App Upper Marcellus category is inclusive of hybrid wells 27 Haynesville Northeast Appalachia Southwest Appalachia Production (MMcfe/d) 3,193 2,610 1,597 Production Expense ($/Mcfe) $0.28 $0.19 $0.29 Differential to NYMEX ($/Mcf) $(0.20) $(0.31) $(0.38) GP&T ($/Mcfe) $0.79 $0.87 $1.37 Rigs 7 3 2 Spuds (by zone) Haynesville 12 Bossier 4 Lower 8 Upper(1) 14 Marcellus 12 Utica 1 TILs (by zone) Haynesville 18 Bossier 8 Lower 16 Upper(1) 14 Marcellus 10 Utica 0 D&C Capex ($mm) $304 $159 $115 Total Capital ($mm) $367 $207 $154
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Haynesville Northeast Appalachia Southwest Appalachia Haynesville Bossier Lower Marcellus Upper Marcellus Marcellus Utica 2026 PDP Decline (12-month decline) ~55% ~25% ~30% Differential (1) to NYMEX ($/Mcf) ($0.31) – ($0.41) ($0.25) – ($0.35) ($0.36) – ($0.46) Production Expense ($/Mcfe) $0.27 – $0.32 $0.15 – $0.20 $0.30 – $0.35 GP&T (2) ($/Mcfe) $0.78 – $0.88 $0.87 – $0.97 $1.41 – $1.51 Wells / Rig / Year ~12 ~29 ~24 Well Spacing (ft) 1,050 – 1,320 1,250 – 1,500 800 – 900 1,200 – 1,400 Avg. 2026 Lateral Length (ft) 10,500 – 11,500 11,000 – 12,000 13,500 – 14,500 13,000 – 14,000 18,500 – 19,500 16,000 – 17,000 2026 Rigs 7 3 1 – 2 Spuds ~55 ~30 ~28 ~57 ~32 ~12 TILs ~50 ~35 ~35 ~45 ~43 ~11 Avg. WI / NRI ~92% / ~73% ~58% / ~49% ~86% / ~71% ~96% / ~79% D&C ($/ft) $1,225 – $1,325 $1,400 – $1,500 $800 – $900 $725 – $825 $650 – $750 $850 – $950 2026 Modeling Assumptions (1) SW App Differential ($/Mcf) represents residue gas only (2) SW App GP&T ($/Mcfe) is inclusive of gas, oil and NGL expenses 28 4Q & FY 2025 Earnings
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Haynesville Drilling Excellence Enhances Returns 4Q & FY 2025 Earnings 29 People • >15-year basin experience • EXE accounts for ~30% of all HSVL laterals ever drilled Processes • Temperature management • ROP optimization • Peak move process Providers • Vertical integration (5 EDC rigs in HSVL) • Industry-leading OFS partners 0 4,000 8,000 12,000 0 400 800 1,200 FY23 FY24 FY25 FY26 Lateral Length ft/d Average ft/d Average LL ▪ Superior expertise in deep, high temperature areas of Haynesville play such as the NFZ ▪ Efficiencies and lateral length extensions driving breakeven improvements ▪ Seeing results translate to early Western Haynesville performance Key Factors for Leading Drilling Performance ~45% Increase in NFZ Drilling Performance Programs Proprietary technology including: • DrillOpsIQ platform • Build and Turn tool • SEER tool
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0 25 50 75 100 1/1/2026 4/1/2026 7/1/2026 10/1/2026 1/1/2027 4/1/2027 7/1/2027 10/1/2027 1/1/2028 Illustrative Productive Capacity of an Average Haynesville Rig Year (Cumulative Net Production, Bcf) HSVL Peers 2024 HSVL Peers 2025 EXE 2024 EXE 2025 Differentiated Haynesville Productivity and Rig Efficiency 4Q & FY 2025 Earnings 30 ~50% more production over a two-year period compared to average Haynesville peer ▪ EXE produces more volume per rig than peer average ▪ Facilitates lower well and asset breakevens, now below $2.75/Mcf ▪ Yields >15% lower program reinvestment rate Yr1 Rig Cum. Yr2 Rig Cum. 2-Yr Rig Total 2024 HSVL Peer Average ~12 Bcf ~31 Bcf ~43 Bcf EXE Average ~19 Bcf ~49 Bcf ~68 Bcf 2025 HSVL Peer Average ~14 Bcf ~40 Bcf ~53 Bcf EXE Average ~21 Bcf ~57 Bcf ~78 Bcf (1) Sourced from Enverus. Peers include: Aethon, Apex, BP, CRK, Exco, GEPII, Sabine, Silverhill, TGNR, Trinity
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Five fundamentals that drive our decision-making and increase our ability to deliver for our stakeholders: Our Commitments: ▪ 100% RSG portfolio recertified in 2025 ▪ Net zero Scope 1 and 2 GHG emissions by 2035 ▪ Transparent disclosures built on a foundation of sustainability reporting Connecting Affordable, Reliable and Lower Carbon Energy to Growing Demand 31 4Q & FY 2025 Earnings 1 2 3 4 5 Ensure a safe and inclusive workplace, promoting collaboration and innovation Take meaningful action to support community well-being Implement environmentally sound operations that mitigate impact and protect ecosystems Minimize emissions in support of delivering lower-carbon energy to sustain economic progress Provide transparent and measurable information to encourage accountability
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Haynesville, Northeast and Southwest Appalachia Sales Points 4Q & FY 2025 Earnings (1) Historical prices based on NYMEX contract settlement for January 2024 – December 2025; current prices based on NYMEX settled and future prices for January 2026 – December 2027, strip as of 2/11/2026 (2) Percentage of production based on 2026 Production Guidance 32 Haynesville Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current CGML ($0.25) CGML ($0.26) TGT ($0.22) TGT ($0.21) TETCO WLA ($0.10) TETCO WLA ($0.13) HAYNESVILLE TOTAL PRODUCTION(2) CGML/TGT 45% TETCO WLA/NYMEX/Other 55% Northeast Appalachia Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current TETCO M3 ($0.16) TETCO M3 +$0.44 Leidy ($0.66) Leidy ($0.62) Eastern Gas ($0.73) Eastern Gas ($0.78) TGP 300L ($0.74) TGP 300L ($0.73) NE APP TOTAL PRODUCTION(2) In Basin 55% Out of Basin 45% Leidy 30% TETCO M3 25% Eastern Gas 20% NYMEX 20% TGP 300L 5% Southwest Appalachia Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current TCO ($0.58) TCO ($0.54) TrunklineZ1A ($0.29) TrunklineZ1A ($0.27) CGML ($0.25) CGML ($0.26) CG Onshore ($0.11) CG Onshore ($0.08) Rex Zone 3 ($0.28) Rex Zone 3 ($0.24) SW APP TOTAL PRODUCTION(2) TCO 40% TrunklineZ1A 25% CGML 15% CG Onshore 10% Rex Zone 3 10% L O U I S I A N A T E X A S N E W Y O R K P E N N S Y L V A N I A O H I O P E N N S Y L V A N I A W E S T V I R G I N I A
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NATURAL GAS ESTIMATED NYMEX GAS SETTLEMENT ($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 2026 100.8 3.98 307.8 3.50 5.09 13.3 3.92 4.73 2.67 1Q 2026 (150) (300) (392) (462) 2Q 2026 133.4 3.88 213.9 3.43 4.77 89.2 3.52 4.23 2.48 2Q 2026 692 257 (19) (295) 3Q 2026 145.4 3.85 194.8 3.47 4.88 104.9 3.68 4.54 2.64 3Q 2026 731 286 (25) (271) 4Q 2026 120.8 3.95 162.5 3.57 5.07 109.3 3.88 5.04 2.75 4Q 2026 697 304 (4) (174) FY 2026 500.4 $3.91 878.9 $3.49 $4.96 316.7 $3.71 $4.63 $2.64 FY 2026 $1,970 $547 ($440) ($1,202) 1Q 2027 90.1 3.96 160.9 3.75 5.14 97.7 3.96 5.06 2.82 1Q 2027 653 303 (0) (142) 2Q 2027 134.5 3.80 65.7 3.61 4.57 69.2 3.53 4.23 2.59 2Q 2027 455 185 (28) (244) 3Q 2027 135.9 3.80 23.2 3.70 4.37 51.5 3.63 4.17 2.62 3Q 2027 369 158 (28) (220) 4Q 2027 82.7 3.82 21.4 3.70 4.32 43.0 3.66 4.20 2.64 4Q 2027 258 111 (16) (146) FY 2027 443.2 $3.84 271.2 $3.71 $4.87 261.3 $3.73 $4.52 $2.69 FY 2027 $1,735 $757 ($72) ($752) 1Q 2028 25.5 3.80 – – – 25.5 3.77 4.75 2.88 1Q 2027 91 40 (5) (37) Reducing Risk, Protecting Returns Through Hedge Program 4Q & FY 2025 Earnings Hedge position as of 2/11/2026 33
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Hedged Financial Basis 4Q & FY 2025 Earnings 34 HAYNESVILLE NORTHEAST APPALACHIA Date TETCO WLA TGT Z1 TETCO M3 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 1Q 2026 1.4 0.11 14.9 (0.22) 36.2 0.47 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) 146.3 ($0.33) 86.1 ($0.97) 62.5 ($1.01) 1Q 2027 – – – – 6.8 0.98 10.8 (0.76) 4.5 (0.88) Hedge position as of 2/11/2026
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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 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 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 4Q & FY 2025 Earnings 35
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4Q & FY 2025 Earnings (1) Includes an adjustment for costs incurred related to the Southwestern merger 36 Three Months Ended December 31, 2025 Three Months Ended December 31, 2024 Year Ended December 31, 2025 Year Ended December 31, 2024 ($ in millions) Net Income (Loss) (GAAP) $ 553 $ (399) $ 1,819 $ (714) Adjustments: Interest expense 59 64 235 123 Income tax expense (benefit) 134 (22) 463 (127) Depreciation, depletion and amortization 759 647 2,980 1,729 Exploration 16 3 46 10 Unrealized (gains) losses on natural gas, oil and NGL derivatives (179) 490 (361) 979 Separation and other termination costs – – 5 23 (Gains) losses on sales of assets 68 (2) 65 (14) Other operating expense, net(1) 11 267 29 325 Impairments 37 – 37 – (Gains) losses on purchases, exchanges or extinguishments of debt – (1) (4) 1 Contract amortization (32) (57) (203) (57) Other (1) (26) (33) (83) Adjusted EBITDAX (Non-GAAP) $ 1,425 $ 964 $ 5,078 $ 2,195 Three Months Ended December 31, 2025 Three Months Ended December 31, 2024 Year Ended December 31, 2025 Year Ended December 31, 2024 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 956 $ 382 $ 4,575 $ 1,565 Cash capital expenditures (741) (536) (2,736) (1,557) Free Cash Flow (Non-GAAP) 215 (154) 1,839 8 Cash paid for merger expenses 3 231 85 269 Cash contributions to investments – (4) (14) (75) Adjusted Free Cash Flow (Non-GAAP) $ 218 $ 73 $ 1,910 $ 202 Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (Unaudited) Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Unaudited)
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4Q & FY 2025 Earnings 37 Reconciliation of Total Debt to Total Capitalization (Unaudited) December 31, 2025 ($ in millions) Total Debt (GAAP) $ 5,009 Premiums, discounts and issuance costs on debt 16 Principal Amount of Debt 5,025 Cash and cash equivalents (616) Net Debt (Non-GAAP) 4,409 Total stockholders’ equity 18,578 Total Capitalization (Non-GAAP) $ 22,987 Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDAX (Unaudited) Three Months Ended December 31, 2025 Three Months Ended December 31, 2024 Year Ended December 31, 2025 Year Ended December 31, 2024 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 956 $ 382 $ 4,575 $ 1,565 Changes in assets and liabilities 427 345 285 315 Interest expense 59 64 235 123 Current income tax expense (benefit) 6 (4) 15 (4) Share-based compensation (12) (9) (46) (38) Other(1) (11) 186 14 234 Adjusted EBITDAX (Non-GAAP) $ 1,425 $ 964 $ 5,078 $ 2,195 (1) Includes an adjustment for costs incurred related to the Southwestern merger