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4Q & FY 2024 Earnings FEBRUARY 26, 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 (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended. Forward -looking statements include certain projections for the full year and first quarter 2025 regarding the Company’s 2025 strategic objectives, our current expectations or forecasts of futur e events, including matters relating to expected synergies from our merger with Southwestern Energy Company ("Southwestern"), ou r capital returns framework, our productive capacity strategy, our ability to continue to pay cash dividends, our ability to capture synergies, the amount and timing of any cash dividends, our sustainability initiatives, as well as statements reflecting expectations, intentions, assump tions or beliefs about future events and other statements that do not relate strictly to historical or current facts. 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 investors or required to be disclosed in our filings with the Securities and Exchange Commission (“SEC”). In addition, historical, current, and forwar d-looking environmental, social and sustainability -related statements may be based on standards for measuring progress that are sti ll developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Forward -looking statements often address our expected future business, financial performance and financial condition, and often contain words such as “aim”, “pr edict”, “should”, “expect,” “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 sta tements are not forward-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. Partic ular uncertainties that could cause our actual results to be materially different than those expressed in our forward -looking statements include: ▪ natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a materi al adverse effect on our business; ▪ Reduced demand for natural gas, oil, and natural gas liquids; ▪ negative public perception regarding us or our industry could have an adverse effect on our operations; ▪ competition in the natural gas and oil exploration and production industry; ▪ risks related to potential acquisitions or dispositions; ▪ if commodity prices fall or drilling efforts are unsuccessful, we may be required to record write -downs of the carrying value of our natural gas and oil properties; ▪ significant capital expenditures required to replace our reserves and conduct our business; ▪ if we are not able to replace reserves, we may not be able to sustain production; ▪ actual quantities of and future net revenues from our proved reserves may be less than our estimates; ▪ our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted return s; ▪ certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed; ▪ our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy t heir obligations to us. ▪ natural gas and oil operations are uncertain and involve substantial costs and risks; ▪ our ability to produce natural gas, oil and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically; ▪ our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject t o interruptions that could adversely affect our cash flow; ▪ our business strategy is increasingly focused on participating in the global LNG value chain, which is dependent, in part, on the growing U.S. LNG export market, a highly regulated and capital -intensive industry with a number of inherent commercial risks. U.S. LNG exports have helped drive domestic demand for natural gas, and, as a natural gas producer, we could be materially and adversely impacted by a deterioration in the U.S. LNG export industry, which could in turn reduce demand for natural gas; ▪ regional epidemics or pandemics and related economic turmoil, including supply chain constraints, have affected, and could in the future adversely affect our business, financial condition, results of operations and cash flows; ▪ Terrorist activities and/or cyber-attacks targeting systems and infrastructure used by the natural gas and oil industry and rela ted regulations may adversely impact our operations; ▪ a deterioration in general economic, political, business or industry conditions would have a material adverse effect on our r esults of operations, liquidity and financial condition; ▪ we have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable ter ms is limited by industry conditions; ▪ restrictive covenants in certain of our existing and future debt instruments may limit our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interest s. ▪ failure to successfully integrate the business of the Company and Southwestern or realize the anticipated benefits of the Sou thwestern merger may adversely affect our future results and financial condition; ▪ we are subject to extensive governmental regulation, which can change and could adversely impact our business, including thro ugh increased costs to comply; ▪ increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may imp act our business, financial results or stock price. ▪ taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business; ▪ completion of the Southwestern merger triggered an annual limitation on the utilization of our tax attributes, reducing our a bility to offset future taxable income, which may result in an increase to income tax liabilities. In addition, trading in our c ommon stock, additional issuance of common stock, and certain other stock transactions could lead to an additional, potentially more restrictive, annual limitation; ▪ weather conditions; ▪ the price and availability of alternative fuels; ▪ U.S. exports of natural gas, oil, liquefied natural gas and NGL; ▪ the ability of the members of OPEC+ and others to agree to and maintain oil price and production controls; ▪ increased use of competing energy products, including alternative energy sources; ▪ political instability or armed conflict in natural gas and oil producing regions, including in connection with the continued armed conflict and instability in Europe and the Middle East; ▪ acts of terrorism; ▪ domestic and global economic and political conditions; and ▪ other factors that are described under Risk Factors in Item 1A of our 2024 Form 10 -K. This presentation references non-GAAP financial measures and metrics. Please see Appendix, which includes definitions of non -GAAP measures and metrics used in this presentation and reconciliations of non -GAAP measures to the most directly comparable GAAP m easure. 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 4Q & FY 2024 Earnings
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Expanding Returns, Expanding Opportunities 3 Attractive, Connected Portfolio 4Q & FY 2024 Earnings 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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Highlights 4 Investment Grade Credit Rating Largest Domestic Natural Gas Producer Accelerating 2025 Synergy Capture to ~$400mm Authorized $1bn Share Repurchase Program To be deployed within returns framework 2025 Plan: ~7.1 Bcfe/d, ~$3.0bn Capex ~$2.7bn base capital (delivers ~7.1 Bcfe/d in 2025) + ~$300mm of productive capacity capex (creates ~300 MMcfe/d uplift available by 1Q26) Enhanced Capital Returns Framework Tranche 1: Base Dividend Tranche 2: $500mm of net debt reduction Tranche 3: 75% remaining FCF to buybacks / variable dividends, 25% to cash on hand Debut $750mm IG issuance during 4Q24, setting record spread for energy rising star (+132 bps to 10-year Treasury) 4Q24 beat with net production of ~6.41 Bcfe/d, ~$1bn of Adj. EBITDAX(1) and ~$600mm of Capex ~$500mm of total synergies expected annually 4Q & FY 2024 Earnings (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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4Q & FY 2024 EARNINGS 2025 Outlook
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6,412 ~6,750 ~7,100 ~7,200 ~300 4Q24A 1Q25E 2025E 2026E / Run-rate ▪ Generating attractive FCF from 2024 productive capacity ▪ Expecting to exit 2025 at ~7.2 Bcfe/d, turning in line substantially all productive capacity built in 2024 (1) ▪ Productive capacity investment in 2H25 facilitates averaging ~7.5 Bcfe/d of production in 2026 should market fundamentals warrant Production Outlook 4Q & FY 2024 Earnings6 Growing Annual Production from 2024 Productive Capacity Activation (MMcfe/d) 2025 Production Plan: ~7.1 Bcfe/d 6 (1) Assumes 100% of DTILs and ~85% of DUCs built from 2024’s productive capacity program are TIL’d in 2025 EstimatesActual ~7,500
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Historical and Future Expected Rig and Production Activity 7 4Q & FY 2024 Earnings 16 23 21 16 ~12 ~15 1 – 3 2021 2022 2023 2024 2025E 2026E Average Rig Count (1) 5,443 8,195 7,958 6,868 ~7,100 ~7,200 ~300 2021 2022 2023 2024 2025E 2026E Historical and Future Estimated Production (1) Running up to 15 rigs in 2H25 creates productive capacity for 2026 ~300 MMcfe/d of productive capacity by 2026 if market fundamentals warrant ~15 rigs as of merger close ~7,500 (1) 2021, 2022, 2023 and 2024 rig count and production is inclusive of Legacy CHK and Legacy SWN Marcellus and Haynesville progra ms
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~$1,200 $2,505 ~$2,700~$480 ~$550 ~$275 ~$195 ~$300 Haynesville Northeast App Southwest App Other Field Corporate 2025E Capex ▪ ~$3.0bn of total capital spend for 2025 ▪ ~$2.7bn capital delivers ~7.1 Bcfe/d in 2025 ▪ ~$300mm of 2H25 productive capacity capex for 2026 production uplift ▪ Flexibility to remove productive capacity capex if markets materially soften Capital Outlook 8 ~$3.0bn • Leasehold • Workover • PP&E • G&A • Capitalized interest Delivers ~7.1 Bcfe/d in 2025 Productive capacity build (+300 MMcfe/d by 1Q26) 2025 Capital Expenditures Demonstrate Significant Efficiency Relative to Standalone 2024 Programs (Implied Midpoints of 2025 Guidance, $mm) 4Q & FY 2024 Earnings
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4Q & FY 2024 Earnings Optimizing Maintenance Production to Maximize Free Cash Flow (1) 9 (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 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 $2.7 7.25 $2.8 7.50 $3.0 7.75 $3.2 8.00 $3.4 8.25 $3.7 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 Illustrative Annual FCF (2) at Various Mid-cycle Prices, Maintenance Production and Capital
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▪ Once at run-rate, production flexes above and below midpoint based on temporary market dislocations ▪ Capital activity is expected to be more constant through-cycle, building and drawing storage while enhancing operational efficiencies ▪ Relative to today, activity is focused on growing to a midpoint of ~7.5 Bcfe/d – any “overproducing” would require incremental capital or preceding down-cycle ▪ EXE’s asset diversification, hedging strategy, Marketing and Commercial activities and Investment Grade status enhance the value of flexible production Illustrative Productive Capacity Strategy Long-term Production Strategy Focused on Remaining Flexible 10 OVERPRODUCING BAND UNDERPRODUCING BAND Mid-cycle Production Target Capital Allocation Response Production Above Target Production Below Target 4Q & FY 2024 Earnings ~7.5 Bcfe/d midpoint aligns with $3.50 – $4.00 mid-cycle price
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4Q & FY 2024 EARNINGS Attractive, Connected Portfolio
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Scale: Largest natural gas producer in North America with ~1.9mm net acres, ~7.1 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 critical markets and highest value demand centers Longevity: Deep inventory supporting returns for decades (20+ years (1) ) Attractive, Connected Portfolio 4Q & FY 2024 Earnings12 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: ~2,900 MMcfe/d Southwest Appalachia ~566,000 net acres >1,500 gross locations FY25E Prod: ~1,600 MMcfe/d Superior Portfolio Characteristics (1) >5,000 gross locations divided by ~250 annual TILs
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$1.41 $1.72 $1.84 $2.10 $2.15 Peer 1 EXE Peer 2 Peer 3 Peer 4 Southwest App(2) $2.00 $2.16 $2.67 $3.01 $3.33 $3.35 EXE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Haynesville Consistently Outperforming Peers (1) Data source: Enverus; LL weighted historical average, 2020 – 2024 TILs. Haynesville Peers: Aethon, BP, CRK, Sabine, TGNR. Northeast App Peers: CTRA, EQT, NFG, Repsol. Southwest App Peers: AR, CNX, EQT, RRC. (2) Southwest App production numbers calculated using a 20:1 ratio for oil and 7:1 ratio for NGLs 13 Capital Efficiency Leader Across the Premier Gas Basins ($/12-month Mcfe) (1) 4Q & FY 2024 Earnings $1.84 $2.12 $2.60 $3.72 $4.80 EXE Peer 1 Peer 2 Peer 3 Peer 4 Northeast App
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Accelerating 2025 Synergy Capture to ~$400mm 14 Annual Synergy Outlook ($mm) $200 $110 $100 $50 $40 Corporate & Regional Costs D&C Cost Savings Other Operating & Capital Initial Synergy Target @ 1/11/2024 Additional Identified Synergies Updated Synergy Target ~$500/yr expected by YE26 ~$400 expected in 2025 ~$400/yr F O C U S A R E A S • ~$170mm of comp- related G&A synergy capture • ~$30mm of non- comp-related G&A synergy capture • ~$110mm from HSVL drilling optimization • ~$15mm from increased utilization of existing, owned water infrastructure • ~$35mm from extending laterals from combined acreage position • ~$15mm from company- owned sand mine in the Haynesville • ~$15mm from completion design optimization • ~$10mm from lower financing costs 4Q & FY 2024 Earnings $200 $130 $70 $1002025 Synergy 2026+ Synergy
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Post-Close Performance Improvements on Legacy SWN Acreage Mobilization 2.8 days Surface Section 0.7 days Intermediate Section 2.2 days Production Section 3.1 days ▪ Initial synergies highly leveraged to Haynesville ▪ Standardizing how we drill across the rig fleet ▪ Improvements seen across all hole sections ▪ Significant progress made in mobilization +20% Improvement of Haynesville Drilling Performance 4Q & FY 2024 Earnings15 489 ~595 Pre-Announcement Post-Close Legacy SWN Performance (Footage per Day) $434 ~$335 Pre-Announcement Post-Close Legacy SWN Performance (Average Cost per Foot) ~23% decrease ~22% increase 8.8 days / $1.4mm improvement per well in 4Q24
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▪ EXE-owned Louisiana sand mine • Began providing sand to operations on 2/1/2025 • Reduced cost per ton that scales as utilization increases ▪ Completions design standardization in NE Appalachia and Haynesville • Multi-disciplinary teams optimizing well cost and productivity • Each asset has begun implementing a standardized design ▪ Meaningful scale leading to reduced service and consumables costs • HHP / Sand / Chems more competitive because of merger • Positions EXE to avoid unnecessary costs ▪ Expansion of wet sand and pile systems to combined Haynesville fleets Material Progress with Completions Synergies in 2025 4Q & FY 2024 Earnings16 ~$30mm in full year 2025 completions synergies EXE-owned Geaux Prop Sand Mine in Northwest Louisiana
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2,338 ~ 2,600 ~ 2,900 4Q24 1Q25 FY25 Haynesville: Premium Markets with Scalable Growth 17 Rig Count 8 7 7 – 9 Crew Count 3 3 3 ▪ 2025 volume growth via productive capacity, development plan optimization, and drilling synergy realization ▪ 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 Production (MMcfe/d) 4Q & FY 2024 Earnings GuidanceActuals Net Acreage ~664,000 Avg. WI / NRI ~92% / ~73% L O U I S I A N A T E X A S EXE Acreage (1) Expand Drilling Company
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N E W Y O R K P E N N S Y L V A N I A Net Acreage ~700,000 Avg. WI / NRI ~51% / ~42% 2,425 ~ 2,675 ~ 2,600 4Q24 1Q25 FY25 Northeast Appalachia: Low Breakeven, Cash Flow Machine 18 ▪ DTIL activation, operational efficiencies and enhanced completion designs position company to maintain production with low rig count ▪ Third rig deployed in 2H25 to maintain productive capacity into 2026 ▪ Foundational cash flow and low reinvestment rate underpins base dividend 4Q & FY 2024 Earnings GuidanceActuals Northeast Appalachia Production (MMcfe/d) Rig Count 2 2 2 – 3 Crew Count 2 2 2EXE Acreage
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EXE Acreage Net Acreage ~566,000 Avg. WI / NRI ~83% / ~68% 1,649 ~ 1,475 ~ 1,600 4Q24 1Q25 FY25 Southwest Appalachia: Liquids Exposure and Upside Potential 19 ▪ Capital program transitioning from front-end loaded to level-loaded activity across 2025 ▪ Asset delivers attractive liquids exposure through significant NGL and condensate production ▪ Acreage landscape offers valuable opportunities for lateral length additions and inventory growth 4Q & FY 2024 Earnings GuidanceActuals ~65% Gas ~30% NGLs ~5% Oil Southwest Appalachia Production (MMcfe/d) Rig Count 2 2 2 – 3 Crew Count 1 2 1 – 2 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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4Q & FY 2024 EARNINGS Marketing & Commercial: Answering the Call for Growing Demand
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▪ Advantaged transportation portfolio provides: • Deliverability • Diversification • Flexibility ▪ Established supplier of choice to global LNG exporters and domestic end users ▪ Creating global platform to expand marketing and commercial business ▪ ~7.5 Bcf/d (1) of firm transportation capacity augmented by physical sales to distribute timing, price and execution risk ▪ Realizing immediate benefits of combined portfolio and leveraging assets for incremental volume to premium markets Ready to Answer the Call for Growing Demand APP: Greater Appalachia ~33% APP: Canada ~1% APP: Northeast/ Citygate ~11% APP: Midwest ~1% APP: Gulf Coast ~7% HSVL: Gulf Coast ~21% APP: Southeast ~4% APP: GC LNG Corridor ~2% HSVL: GC LNG Corridor ~20% 4Q & FY 2024 Earnings21 (1) Assumes Momentum NG3 pipeline projected in -service 4Q25
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Ready to Answer the Call for Growing Demand (1) 1.0 Bcf/d of Gillis volume aligns with Momentum NG3 pipeline projected in -service in 4Q25 22 ▪ NE Appalachia • ~1 Bcf/d flows east to premium priced Northeast points • Premium pricing to NYMEX driven by strong Citygate demand during winter months ▪ SW Appalachia • ~0.7 Bcf/d of capacity with access to Perryville and other key LNG corridor supply points Advantaged transportation portfolio expected to provide deliverability, diversification and flexibility 4Q & FY 2024 Earnings Selected, Strategic Market Access Contracts Market Area Volume (Bcf/d) Reference Index Gillis 2.5(1) TETCO WLA, NYMEX Southeast 0.7 CGT Onshore, Transco Zn3 – Zn5, TGP 500L, FGTZn2, SoNat Perryville 2.4 TGT Zn 1, CGML, TrunklineZ1A Citygate 0.8 TETCO M3 Midwest 0.2 REX Zn3, Dawn ~75% of EXE Marketed 2026 Volume to Strategic Markets NYC Boston Perryville / Gulf Coast ▪ Haynesville • Haynesville portfolio balanced between growing LNG demand and Southeast power demand sourced from Perryville • Up to 2.5 Bcf/d of capacity to Gillis, directly connected to premium markets in the LNG corridor • LNG demand growing more than 11 Bcf/d over the next three years • ~2 Bcf/d of capacity to growing Perryville markets • ~3 Bcf/d of new demand-pull pipeline projects recently announced from Perryville Perryville Gillis
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14.9 14.9 14.9 14.9 4.8 7.3 11.5 24.3 2024 2025 2026 2027 2028+ Online LNG Under Construction LNG FERC and DOE Approved LNG ▪ Fully financed, under construction LNG projects increase U.S. capacity >40% ▪ 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 4Q & FY 2024 Earnings (1) Volumes per FERC; Inservice estimations from EIA and project websites 23 >11 Bcf/d of incremental LNG export capacity expected by 2027 Growing Exports Expected to be Significant to U.S. Gas Demand (U.S. LNG Capacity, Bcf/d)(1) 2025: Plaquemines Corpus Christi 2026: Golden Pass 2027: Sempra – Port Arthur Rio Grande Plaquemines Lake Charles Magnolia Sempra – Cameron Freeport Gulf Eagle Texas Brownsville Alaska Gasline Commonwealth Delfin LNG Woodside Calcasieu Pass Freeport Cameron Corpus Christi Elba Island Cove Point Sabine Pass New Fortress
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4Q & FY 2024 EARNINGS Peer-Leading Returns
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Program designed to return cash to shareholders and reduce net debt ▪ Tranche 1 – Annual Base Dividend • $2.30/share • Remains priority and is paid through-cycle • 4Q24 DPS of $0.575/sh to be paid in March ▪ Tranche 2 – Net Debt Reduction • Brings consistent annual net deleveraging efforts into focus • 2025 target of $500mm from within annual FCF • Eagle Ford divestiture proceeds of ~$116mm flow to net debt reduction ▪ Tranche 3 – Additional Returns to Equity • Expect 75% of remaining FCF in form of equity return (variable dividend or share repurchases) • $1bn share repurchase authorization in place Enhanced Capital Returns Framework Total FCF Additional Returns to Equity Net Debt Reduction Annual Base Dividend EXCESS FCF REMAINING FCF Var Div. / Buyback 75% Cash 25% $500mm $2.30/ share Additional Returns to Equity $116mm (1) (1) $116mm related to EF divestitures (2) Capital Returns Framework utilizes Adjusted FCF 4Q & FY 2024 Earnings25 (2)
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4Q & FY 2024 EARNINGS Resilient Financial Foundation
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4Q & FY 2024 Earnings ▪ Investment Grade Ratings • BBB- from S&P • BBB- from Fitch • Ba1 from Moody’s (positive outlook) ▪ Financial Policy Targets • ~$1.1bn in debt retirement by YE25 • <1.0x net debt / Adj. EBITDAX (1) (~$4.5bn or less net debt) ▪ Fulfilling Commitments • Enhanced return framework prioritizing debt reduction • Reduced debt by ~$1bn since close, including the termination of the SWN revolver Investment Grade Rating Demonstrates Resilient Financial Foundation 27 Enhanced market access Unsecured credit facility Reduced cost of capital Expanded commercial opportunities BENEFITS OF INVESTMENT GRADE $47 $2,500 $950 6.75% $1,200 $1,150 $500 5.875% $700 5.375% $750 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Expand Energy Debt Maturity Profile ($mm) (2) ~6.10% ~6.00% 5.375% 4.75% EXE RBL Capacity 5.70% 5.50% (1) A non-GAAP measure as defined in the Appendix (2) As of 1/31/2025
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EXE’s Recurring Hedge Strategy Preserves Upside and Minimizes Downside Through-Cycle 28 RETURNS ENHANCING ▪ Price volatility moves faster than capital planning cycles, creating cash flow consistency and preserving through-cycle returns ▪ Hedging assures attractive returns on deployed capital (price volatility moves fast) ▪ Right structures at the right time create right-way risk HEDGING STRATEGY FUNDAMENTALS ▪ Specific hedging target percentages reflect expected wedge production from capex ▪ Combination of programmatic and opportunistic hedging depending on cycle ▪ Structures are relatively simple with majority costless collars and swaps 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 5th Quarter 6th Quarter 7th Quarter 8th Quarter Illustrative Hedge-the-Wedge Approach (% Volume Hedged) 50% – 60% of Production Hedged 20% – 45% of Production Hedged 4Q & FY 2024 Earnings
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Current Hedge Position Preserves Upside as Prices Strengthen 29 251 246 258 232 104 21 32 14 75 95 80 75 167 169 126 98 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 3Q26 4Q26 Hedged Natural Gas Volumes Current Hedge Book Supports Near-Term Realizations and Preserves Upside $3.78 $4.27 $4.48 $4.71 $4.77 $3.92 $4.13 $4.38 $4.40 $4.15 $4.18 $4.49 $4.95 $4.53 $4.56 $4.69 $3.44 $3.34 $3.35 $3.37 $3.42 $3.42 $3.43 $3.48 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 3Q26 4Q26 Ceiling and Floor (1) ($/MMbtu) Realized Price Strip 4Q & FY 2024 Earnings (1) As of 2/19/2025 Added since 3Q Earnings (Bcf) Last Public Disclosure (Bcf)
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4Q & FY 2024 EARNINGS Responsible Stewardship 30
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Five fundamentals that drive our decision-making and increase our ability to deliver for our stakeholders: Our Commitments: ▪ 100% Responsibly Sourced Gas (RSG) portfolio ▪ 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 Markets in Need 31 4Q & FY 2024 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 operations designed to mitigate environmental 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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Appendix 4Q & FY 2024 EARNINGS
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Management’s Guidance as of February 26, 2025 33 Production (MMcfe/d) 4Q24A 1Q25E 2025E Total Production 6,412 6,700 – 6,800 7,000 – 7,200 Haynesville 2,338 ~2,600 ~2,900 Northeast Appalachia 2,425 ~2,675 ~2,600 Southwest Appalachia 1,649 ~1,475 ~1,600 Capital Expenditures ($mm) 4Q24A 1Q25E 2025E Total D&C $500 $550 – $600 $2,150 – $2,300 Haynesville 60% ~52% ~54% Northeast Appalachia 19% ~19% ~22% Southwest Appalachia 21% ~29% ~24% Other Capex (Field)(2) $51 $80 – $95 $275 – $300 Other Capex (Corporate)(3) $42 $45 – $55 $175 – $200 Total Base Capital Expenditures $593 $675 – $750 $2,600 – $2,800 Productive Capacity Program up to $300 Total Capital Expenditures $593 $675 – $750 $2,900 – $3,100 Operating Costs (per Mcfe of Projected Production) 4Q24A 2025E Production Expense $0.27 $0.25 – $0.30 Gathering, Processing and Transportation (GP&T) $1.04 $0.96 – $1.11 GP&T Expense $0.94 $0.90 – $1.00 GP&T FMV Liability (1) $0.10 $0.06 – $0.11 Severance and Ad Valorem Taxes $0.07 $0.08 – $0.10 General and Administrative $0.09 $0.08 – $0.12 Depreciation, Depletion and Amortization $1.09 $1.05 – $1.15 Corporate Expenses ($mm) 4Q24A 2025E Interest Expense $64 $250 – $275 Cash Income Tax ranges at flat prices $0 $3.50 $175 – $225 $4.00 $300 – $350 $4.50 $450 – $500 Basis Differentials (excluding hedges) 4Q24A 2025E Estimated (E) Basis Deduct to NYMEX Prices, based on 2/19/2025 Strip Prices: Natural Gas ($/Mcf) ($0.34) ($0.30) – ($0.45) Oil ($/bbl) ($9.86) ($10.00) – ($12.00) NGL (% of WTI) 39% 35% – 45% 4Q & FY 2024 Earnings (1) GP&T fair market liability related to the amortization of the $175mm – $225mm net liability for out-of-market contracts assumed in the Southwestern merger (2) Other Capex (Field) includes Leasehold and Workover expenses (3) Other Capex (Corporate) includes PP&E, Capitalized G&A and Interest expenses
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4Q24 EXE Business Unit Results 34 Haynesville NE Appalachia SW Appalachia Production (MMcfe/d) 2,338 2,425 1,649 Production Expense ($/Mcfe) $0.33 $0.18 $0.32 Differential to NYMEX ($/Mcfe) $(0.22) $(0.45) $(0.36) GP&T ($/Mcfe) $0.74 $0.87 $1.33 Rigs 8 2 2 Spuds (by zone) Haynesville 13 Bossier 8 Lower 6 Upper 7 Marcellus 7 Utica 3 TILs (by zone) Haynesville 13 Bossier 12 Lower 7 Upper 8 Marcellus 1 Utica 0 D&C Capex ($mm) $300 $97 $103 Total Capital ($mm) $348 $116 $129 4Q & FY 2024 Earnings
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2025 Modeling Assumptions 35 Haynesville NE Appalachia SW Appalachia Haynesville Bossier Lower Marcellus Upper Marcellus Marcellus Utica 2025 PDP Decline (12-month decline) ~45% ~30% ~25% Differential (1) to NYMEX ($/Mcf) ($0.20) – ($0.30) ($0.45) – ($0.55) ($0.25) – ($0.35) Production Expense ($/Mcfe) $0.30 – $0.35 $0.18 – $0.23 $0.30 – $0.35 GP&T (2) ($/Mcfe) $0.70 – $0.80 $0.85 – $0.95 $1.30 – $1.40 Wells / Rig / Year ~10 ~23 ~20 Well Spacing (ft) 1,050 – 1,320 1,400 – 1,450 750 – 850 1,200 – 1,300 Avg. 2025 Lateral Length (ft) 9,500 – 10,500 10,000 – 11,000 13,500 – 14,500 13,000 – 14,000 18,500 – 19,500 16,000 – 17,000 2025 Rigs 7 – 9 2 – 3 2 – 3 Spuds ~45 ~30 ~20 ~37 ~40 ~7 TILs ~70 ~45 ~50 ~65 ~33 ~5 Avg. WI / NRI ~92% / ~73% ~51% / ~42% ~82% / ~67% ~100% / ~80% D&C ($/ft) $1,400 – $1,500 $1,550 – $1,650 $750 – $850 $775 – $875 $700 – $800 $800 – $900 4Q & FY 2024 Earnings (1) SW Appalachia Differential ($/Mcf) represents residue gas only (2) SW Appalachia GP&T ($/Mcfe) is inclusive of gas, oil and NGL expenses
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Illustrative Sensitivities (1) Adjusted EBITDAX inclusive of hedges (2) Cash Flow from Operations excluding changes in Working Capital and inclusive of hedges and ~$100mm in 2025 merger expense (3) Assumes $70/bbl and 40% NGL; assumes basis differentials of ($0.37) natural gas, ($11.00) oil, 40% NGL for 2025 and 2026 (4) Adjusted EBITDAX and Cash Flow from Operations excluding changes in Working Capital are non -GAAP financial measures, see Appendi x for more information 4Q & FY 2024 Earnings36 ~$4.1 ~$4.8 ~$5.7 ~$6.5 ~$4.2 ~$5.2 ~$6.4 ~$7.6 $3.00 $3.50 $4.00 $4.50 Adj. EBITDAX (1,3,4) ($bn) 2025 20262025 (~7.1 Bcfe/d) 2026 (~7.5 Bcfe/d) ~$3.7 ~$4.3 ~$5.0 ~$5.6 ~$3.8 ~$4.6 ~$5.6 ~$6.5 $3.00 $3.50 $4.00 $4.50 Cash Flow from Operations (2,3,4) ($bn) 2025 20262025 (~7.1 Bcfe/d) 2026 (~7.5 Bcfe/d)
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Haynesville, Northeast and Southwest Appalachia Sales Points 37 Haynesville Sales Points DEDUCT FROM NYMEX ($) (1) Historical Avg Current CGML ($0.28) CGML ($0.25) TGT ($0.25) TGT ($0.19) 9% of NYMEX 6% of NYMEX HAYNESVILLE TOTAL PRODUCTION(2) CGML 15% TGT 20% Other (primarily NYMEX) 65% Northeast Appalachia Sales Points DEDUCT FROM NYMEX ($)(1) Historical Avg Current TETCO M3 +$0.05 TETCO M3 ($0.10) Leidy ($0.76) Leidy ($0.80) Eastern Gas ($0.82) Eastern Gas ($0.86) TGP 300L ($0.83) TGP 300L ($0.87) 20% of NYMEX 12% of NYMEX NORTHEAST APPALACHIA TOTAL PRODUCTION(2) In Basin 55% Out of Basin 45% Leidy 30% TETCO M3 25% Eastern Gas 20% NYMEX 20% TGP 300L 5% Southwest Appalachia Sales Points DEDUCT FROM NYMEX ($) (1) Historical Avg Current TCO ($0.67) TCO ($0.63) TrunklineZ1A ($0.28) TrunklineZ1A ($0.25) CG Onshore ($0.13) CG Onshore ($0.02) CGML ($0.28) CGML ($0.25) Rex Zone 3 ($0.18) Rex Zone 3 ($0.22) 15% of NYMEX 7% of NYMEX SOUTHWEST APPALACHIA TOTAL PRODUCTION(2) TCO 40% TrunklineZ1A 25% CG Onshore 15% CGML 10% Rex Zone 3 10% 4Q & FY 2024 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 2/19/2025 (2) Percentage of production based on 2025 Production Guidance
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▪ New return framework effective on 1/1/2025 ▪ Tranche 2 and Tranche 3 are filled based on how much FCF is generated above the base dividend within a six-month evaluation period ▪ 2025 Tranche 2 target is set at $500mm ($250mm per evaluation period) ▪ 75% of Tranche 3 FCF may be used as follows: • Buybacks: Can occur throughout the evaluation period • Variable Dividend: If applicable, will be paid out at the end of the evaluation period Return Framework Mechanics Tranche 2 (Debt Paydown) 4Q24 1Q25 2Q25 3Q25 4Q25 Tranche 3 (Additional Returns to Equity) 38 Return Framework Timeline Merger Close on 10/1 4Q24 1Q25 2Q25 3Q25 4Q25 Return Framework Timeline Tranche 1 (Base Dividend) 3Q Base Div. Paid Out 4Q Base Div. Paid Out 1Q Base Div. Paid Out 2Q Base Div. Paid Out 3Q Base Div. Paid Out Tranche 2 (Net Debt Reduction) Tranche 3 (Additional Returns to Equity) First Evaluation Period for Tranches 2 and 3 (six months) Second Evaluation Period for Tranches 2 and 3 (six months) Any FCF generated beyond base dividend in 4Q24 expected to be used for net debt reduction 4Q & FY 2024 Earnings
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Fully Diluted Share Count Breakdown 39 232.7 232.7 - 8.0 240.7 Shares Warrants Fully Diluted Shares Outstanding As of 2/19/2025 4Q & FY 2024 Earnings
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NATURAL GAS ESTIMATED NYMEX GAS SETTLEMENT ($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 102.9 3.39 182.1 3.41 4.65 39.6 3.66 5.88 2.59 1Q 2025 161 48 (35) (96) 2Q 2025 99.6 3.41 201.3 3.23 4.17 40.0 3.66 5.88 2.59 2Q 2025 456 114 (112) (345) 3Q 2025 95.2 3.48 202.2 3.23 4.17 40.5 3.66 5.88 2.59 3Q 2025 457 119 (95) (326) 4Q 2025 56.8 3.49 209.7 3.28 4.50 40.5 3.66 5.88 2.59 4Q 2025 421 114 (53) (208) FY 2025 354.6 $3.43 795.3 $3.29 $4.37 160.6 $3.66 $5.88 $2.59 FY 2025 $1,494 $395 ($296) ($977) 1Q 2026 16.2 4.02 254.7 3.38 5.01 – – – – 1Q 2026 385 114 0 (91) 2Q 2026 21.8 3.89 168.1 3.36 4.61 – – – – 2Q 2026 269 79 (2) (101) 3Q 2026 23.9 3.85 134.1 3.36 4.69 – – – – 3Q 2026 226 68 (6) (80) 4Q 2026 16.6 4.02 95.5 3.38 4.80 – – – – 4Q 2026 166 54 0 (46) FY 2026 78.5 $3.93 652.4 $3.37 $4.81 – – – – FY 2026 $1,047 $316 ($8) ($278) 1Q 2027 0.0 – 35.6 3.53 5.18 – – – – 4Q 2026 54 19 0 0 Reducing Risk, Protecting Returns Through Hedge Program 40 4Q & FY 2024 Earnings Hedge position as of 2/19/2025
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NATURAL GAS LIQUIDS ESTIMATED NGL SETTLEMENT ($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 0.3 0.0 (0.6) (1.2) 2Q 2025 910 0.25 546 0.74 137 0.84 205 1.35 2Q 2025 0.6 0.1 (0.8) (1.7) 3Q 2025 920 0.25 552 0.74 138 0.84 207 1.35 3Q 2025 0.6 0.1 (0.8) (1.7) 4Q 2025 920 0.25 552 0.74 138 0.84 207 1.35 4Q 2025 0.6 0.1 (0.8) (1.7) FY 2025 3,650 $0.25 2,253 $0.74 548 $0.84 821 $1.35 FY 2025 $2.0 $0.4 ($2.9) ($6.3) FY 2026 – – – – – – – – FY 2026 – – – – Reducing Risk, Protecting Returns Through Hedge Program 41 4Q & FY 2024 Earnings Hedge position as of 2/19/2025
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Reducing Risk, Protecting Returns Through Hedge Program 42 CRUDE OIL ESTIMATED NYMEX WTI SETTLEMENT ($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 2 0 (0) (0) 2Q 2025 – – – – – 364 70.00 94.63 60.00 2Q 2025 4 0 0 0 3Q 2025 – – – – – 368 70.00 94.63 60.00 3Q 2025 4 0 0 0 4Q 2025 – – – – – 322 65.71 86.81 55.71 4Q 2025 2 0 0 (1) FY 2025 41 $77.66 – – – 1,324 $68.96 $92.73 $58.96 FY 2025 $11 $0 ($0) ($1) 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) 4Q & FY 2024 Earnings Hedge position as of 2/19/2025
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Hedged Financial Basis 43 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) 8.2 (0.90) – – 28.2 (1.00) 2.3 (0.64) 3Q 2025 0.9 (0.23) – – 28.8 (0.24) 8.3 (0.90) – – 28.5 (1.00) 2.3 (0.64) 4Q 2025 0.3 (0.23) – – 19.8 (0.23) 4.0 (0.43) – – 13.3 (0.93) 2.3 (0.64) FY 2025 7.5 ($0.22) – – 112.3 ($0.23) 36.2 ($0.01) 0.9 ($0.75) 46.0 ($0.93) 9.1 (0.64) 1Q 2026 – – 1.4 0.11 14.9 (0.22) 1.8 0.64 – – 5.4 ($0.73) – – 2Q 2026 – – 1.4 0.11 – – – – – – – – – – 3Q 2026 – – 1.4 0.11 – – – – – – – – – – 4Q 2026 – – 1.4 0.11 – – – – – – – – – – FY 2026 – – 5.5 0.11 14.9 ($0.22) 1.8 $0.64 – – 5.4 ($0.73) – – 4Q & FY 2024 Earnings Hedge position as of 2/19/2025
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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 certain 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, projected Adjusted Free Cash Flow, and projected Cash Flow from Operations excluding changes in Working Capital 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 similar 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 and oil 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 and is used to determine Expand Energy’s payout of enhanced returns framework. 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. Cash Flow from Operations excluding changes in Working Capital: Cash Flow from Operations excluding changes in Working Capital is defined as net cash provided by (used in) operating activities excluding changes in assets and liabilities.It is presented to provide investors with additional information for comparative purposes within the industry where other companies may have different financing methods and capital structure. Cash Flow from Operations excluding changes in Working Capital 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 44 4Q & FY 2024 Earnings
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45 4Q & FY 2024 Earnings Three Months Ended December 31, 2024 Three Months Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in millions) Net Income (Loss) (GAAP) $ (399) $ 569 $ (714) $ 2,419 Adjustments: Interest expense 64 22 123 104 Income tax expense (benefit) (22) 166 (127) 698 Depreciation, depletion and amortization 647 379 1,729 1,527 Exploration 3 8 10 27 Unrealized (gains) losses on natural gas and oil derivatives 490 (347) 979 (1,278) Separation and other termination costs – 2 23 5 Gains on sales of assets (2) (139) (14) (946) Other operating expense, net(1) 267 4 325 22 (Gains) losses on purchases, exchanges or extinguishments of debt (1) – 1 – Contract amortization (57) – (57) – Other (26) (29) (83) (65) Adjusted EBITDAX (Non-GAAP) $ 964 $ 635 $ 2,195 $ 2,513 Three Months Ended December 31, 2024 Three Months Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 382 $ 470 $ 1,565 $ 2,380 Cash capital expenditures (536) (379) (1,557) (1,829) Free Cash Flow (Non-GAAP) (154) 91 8 551 Cash paid for merger expenses 231 – 269 – Cash contributions to investments (4) (82) (75) (231) Free cash flow associated with divested assets(2) – (48) – (243) Adjusted Free Cash Flow (Non-GAAP) $ 73 $ (39) $ 202 $ 77 Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (Unaudited) Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Unaudited) (1) The 3- and 12-month periods ended December 31, 2024 include an adjustment for costs incurred related to the Southwestern merger. (2) In March and April of 2023, we closed two divestitures of certain Eagle Ford assets. Due to the structure of these transactio ns, both of which had an effective date of October 1, 2022, the cash generated by these assets was delivered to the respective bu yers through a reduction in the proceeds we received at the closing of each transaction. Additionally, in November 2023, we closed the dives titure of the final portion of our Eagle Ford assets, with an effective date of February 1, 2023 and the cash generated by these assets was delivered to the buyer through a reduction in the proceeds we received at the closing of the transaction.
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46 4Q & FY 2024 Earnings Reconciliation of Total Debt to Total Capitalization (Unaudited) December 31, 2024 ($ in millions) Total Debt (GAAP) $ 5,680 Premiums, discounts and issuance costs on debt 6 Principal Amount of Debt 5,686 Cash and cash equivalents (317) Net Debt (Non-GAAP) 5,369 Total stockholders’ equity 17,565 Total Capitalization (Non-GAAP) $ 22,934 Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDAX (Unaudited) Three Months Ended December 31, 2024 Three Months Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in millions) Net Cash Provided by Operating Activities (GAAP) $ 382 $ 470 $ 1,565 $ 2,380 Changes in assets and liabilities 345 93 315 (275) Interest expense 64 22 123 104 Current income tax expense (4) 57 (4) 270 Share-based compensation (9) (8) (38) (33) Other(1) 186 1 234 67 Adjusted EBITDAX (Non-GAAP) $ 964 $ 635 $ 2,195 $ 2,513 (1) The 3- and 12-month periods ended December 31, 2024 include an adjustment for costs incurred related to the Southwestern merger.