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3Q25 Earnings Presentation November 2025
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2 Investor Contacts This presentation contains certain forward-looking statements within the meaning of federal securities laws. Forward-looking statements are not statements of historical fact and reflect Coterra's current views about future events. Such forward-looking statements include, but are not limited to, statements about returns to shareholders, growth rates, enhanced shareholder value, reserves estimates, future financial and operating performance and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, and other statements that are not historical facts contained in this presentation. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this presentation will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the volatility in commodity prices for crude oil and natural gas; cost increases; changes in U.S. and international economic policy (including tariffs and retaliatory tariffs and the impacts thereof); the effect of future regulatory or legislative actions; the impact of public health crises, including pandemics (such as the coronavirus pandemic) and epidemics and any related governmental policies or actions on Coterra’s business, financial condition and results of operations; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption (including as a result of the pandemic or geopolitical disruptions such as the war in Ukraine or the conflict in the Middle East); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, operating expenses and completion of Coterra's annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; results of future marketing and drilling activities (including seismicity and similar data); exploration and development risks; competition; the ability of management to execute its plans to meet its goals; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC, which are available on Coterra's website at www.coterra.com. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, Coterra does not undertake any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof. This presentation includes non-GAAP financial measures, which help facilitate comparison of company performance across periods. For a reconciliation of non-GAAP measures included herein to the nearest corresponding GAAP measure, please see the appendix to this presentation. Disclaimer Cautionary Statement Regarding Forward-Looking Information Daniel Guffey Vice President - Finance, IR and Treasurer daniel.guffey@coterra.com Hannah Stuckey Investor Relations Manager hannah.stuckey@coterra.com COTERRA.COM Investor Relations ir@coterra.com
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3Q25 Production Beat | Beat both mid-points of oil & natural gas production guidance by ~2.5%, with in-line capex; Raising FY25 BOE and natural gas guidance and tightening the range around oil production guidance 3 Key Takeaways from Third Quarter 2025 Update Looking Ahead to 2026 | Anticipate 2026e capex modestly down YoY, while maintaining 0-5% annual BOE & natural gas growth, and ~5% annual oil growth; expect reinvestment rate <50%1 Franklin / Avant Acquisitions Exceeding Expectations | Improvements vs. original expectations: ~5% LOE improvement, with line-of-sight to additional savings; well costs -10%; increased the asset’s inventory footage >10% through trades, leasing, and successful delineation Balance Sheet Remains Top-Tier | Pro forma leverage ~0.8x2, retired $600 million of Term Loans YTD; restarted share repurchase program in 4Q25 Durable Free Cash Flow Outlook | Estimated 2025 Free Cash Flow of ~$2.0 billion1, underpinned by balanced commodity exposure between oil and natural gas Note: See appendix for non-GAAP reconciliations and definitions. Reinvestment rate defined as capex as % of DCF. 1) At recent strip prices. 2) Net debt to pro forma adjusted EBITDAX for the trailing twelve months.
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Beat 3Q25 Midpoint Production Volumes & Raised for the Year Higher production & lower capex driving improved capital efficiency 4Note: Incurred capex shown; not cash basis. See appendix for non-GAAP reconciliations and definitions. 3Q25 actuals vs. guide 2025e guidance update Oil mbod Gas mmcfd Total Volumes mboed Capex 166.8 158.0 168.0 actual guidance 2,895 2,750 2,900 actual guidance 785 740 790 actual guidance $658mm $625mm $675mm actual guidance 159.0 161.0 152.0 168.0 updated guid. February guid. 2,925 - 2,965 2,675 2,875 updated guid. February guid. 772 782 710 770 updated guid. February guid. $2.3bn $2.1bn $2.4bn updated guid. February guid.
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Coterra Energy Key Differentiating Factors 5Note: See appendix for non-GAAP reconciliations and definitions. Competitive Cost Structure Asset Quality Top-Tier Margin & Capital Efficiency Consistent Investment in Deep, High-Quality Inventory FCF Durability, Shareholder Returns, Top-Tier Balance Sheet Culture & Strategy
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6 Asset Quality Demonstrated by Low Break-Evens Peers include APA, AR, CHRD, CIVI, DVN, EOG, EQT, EXE, FANG, MTDR, OVV, OXY, PR, RRC. 1) Source: Enverus Intelligence North American Inventory Analysis. Estimated 15:1 PV-10 Break-Even Oil Price Across L48 Assets1 CTRA vs Peers; 15:1 based on recent strip $39 $40 $40 $41 $42 $42 $42 $42 $43 $43 $43 $45 $46 $46 $50 CTRA
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2023 2024 2025e 2026e 2023 2024 2025e 2026e 2023 2024 2025e 2026e 2023 2024 2025e 2026e CTRA PBU MBU ABU $1,100 $1,020 $790 $770 $1,260 $1,290 $1,060 $1,090 $1,150 $1,020 $950 $910 $1,130 $1,060 $940 $890 2023 2024 2025e 2026e 2023 2024 2025e 2026e 2023 2024 2025e 2026e 2023 2024 2025e 2026e CTRA PBU MBU ABU Sustained Improvement in Fully Burdened Well Costs, Enhancing Economics Driven by longer laterals and efficient operations 71) $ per foot includes drilling, completion, facilities and post-completion capital for CTRA operated wells. Annual Average Well Cost per Foot1 -21% -21% -30% -13%
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8 2026e Revenue per BOE vs Margin Recent strip: Henry Hub of $4.02/mmbtu & WTI of $60/bbl CTRA’s High Quality Assets Produce Top-Tier Margins Peers include APA, CHRD, COP, DVN, EOG, EQT, EXE, FANG, MTDR, OVV, PR, RRC. Source: Factset consensus estimates. CTRA Margin Consistently ~65-70% 71% 71% 70% 67% 67% 64% 62% 61% 59% 51% 50% 49% 42% 0% 10% 20% 30% 40% 50% 60% 70% 80% $0 $5 $10 $15 $20 $25 $30 CTRA 2026e revenue/boe 2026e % margin - right axis 71% 69% 63% 64% 67% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $0 $2 $4 $6 $8 $10 $12 $14 $16 2022 2023 2024 2025e 2026e revenue/boe EBITDA/boe % margin
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1% 9% 2% 5% 1% 3% 3% 2% 5% 0% -3% 3% 4% 10% -1% 3% -3% -1% 1% 3% 5% 7% 9% 11% 13% $0 $5 $10 $15 $20 $25 $30 $35 CTRA 2026e YoY boed growth 20:3:1 $ capital per boe 20:3:1 2025e capital efficiency average capital efficiency consensus 2026e YoY 20:3:1 boed growth Disciplined Capital Program ~$2.3 billion capex & ~55% reinvestment rate1 ~$2.0 billion Free Cash Flow2 Diversified commodity mix and disciplined reinvestment Production Guidance 772-782 mboed | 159-161 mbod | 2,925-2,965 mmcfd Organic Production Growth in 2025e and 2025e-2027e expect ~5% for oil and 0-5% for BOE and gas 9 2025e Operational and Financial Outlook 2025: Top-Tier Capital Efficiency Paired with Industry-Leading Growth Coterra has one of the highest growth rates with best-in-class capital efficiency Note: See appendix for non-GAAP reconciliations and definitions. Source: Factset consensus. CTRA capital efficiency based on 2025e guidance calculated as capex per 20:3:1 boe; production growth estimates based on consensus. Peers include APA, AR, CHRD, CIVI, COP, DVN, EOG, EQT, EXE, FANG, MTDR, OVV, OXY, PR, RRC. 1) Reinvestment rate defined as capex as % of DCF. 2) At recent strip prices. See appendix for commodity price assumptions. 2025e Capital Efficiency and 2026e Production Growth
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10 Disciplined Approach to Capital Investment Differentiated reinvestment rate through the commodity cycles Source: Factset consensus for peers and estimates. Peers include APA, AR, CHRD, CIVI, COP, DVN, EOG, EQT, EXE, FANG, MTDR, OVV, OXY, PR, RRC. Reinvestment rate defined as capex as % of DCF. See appendix for non-GAAP reconciliations and definitions. See appendix for commodity price assumptions. Conservative historical reinvestment rate Low reinvestment among peers in 2026 50% 0% 10% 20% 30% 40% 50% 60% 70% CTRA gas-weighted peers oil-weighted peers 35% 87% 77% 52% 44%42% 63% 59% 60% 61% 51% CTRA Average 25% 35% 45% 55% 65% 75% 85% 95% 2022 2023 2024 2025e 2026e consensus CTRA gas peer average oil peer average CTRA average
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11 Long Runway of High-Quality Inventory Benchmark price assumptions of $75/bbl and $3.75/mmbtu Note: Estimates as of February 2025. See appendix for non-GAAP reconciliations and definitions, and other defined terms. 1) Calculated midpoints based on average 2025e-2027e D&C spend and $75 WTI & $3.75 Henry Hub. ~$31 billion of Economic Capex Opportunities Implied Inventory Duration1 estimates can fluctuate based on assumptions around well spacing, cost levels, commodity prices, & activity cadence ~$14bn, or ~45%, of capex is expected to generate 2.0x PVI10 or better estimated capex by PVI10 bucket: estimated total footage by asset area: $31bn $6bn $8bn $8bn $5bn $4bn >1.0x >2.5x 2.0-2.5x 1.5-2.0x 1.3-1.5x 1.0-1.3x Permian ~15 years Marcellus ~12 years Anadarko ~15 years Total company ~15 years Lea County 23% Culberson County 22% Reeves County 18% Eddy County 9% Marcellus 19% Anadarko 9%
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48% 48% 52% 49% 0% 10% 20% 30% 40% 50% 60% 70% 80% 0 500 1,000 1,500 2,000 2,500 3,000 Low Oil & High Gas High Oil & Low Gas Mid-Cycle Recent Strip FCF capex as % of DCF 5:1 10:1 15:1 20:1 25:1 30:1 35:1 40:1 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Average Oil:Gas Price Ratio 12 Uniquely positioned to weather volatility Diversified commodity portfolio with demonstrated capital flexibility Oil:gas price ratios >20:1: Oil advantaged, occurred 53% 2015-3Q25, 3% 5-yr Strip <17:1: Gas advantaged, occurred 28% 2015-3Q25, 54% 5-yr Strip Durable Free Cash Flow Through the Cycles Oil-to-gas price ratios can, and have historically decoupled, especially during periods of extreme volatility Note: Strip prices as of 10/23/25. Reinvestment rate defined as capex as % of DCF. See appendix for non-GAAP definitions. Resilient Future Free Cash Flow & disciplined reinvestment across price environments WTI & HH Oil:gas price ratio $50 & $4.75 11:1 $75 & $2.75 27:1 $65 & $3.25 20:1 ~$60 & ~$4.00 15:1 recent strip →
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$1,214 $2,000 $635 $672 $451 $47 $75 $600 2024 FCF 2024 uses 2025e FCF 2025e uses FCF annual dividends share repurchases to date debt repayments to date 13 Free Cash Flow in $ millions YoY increase driven by greater oil volumes from Lea County acquisition, higher gas price, and disciplined reinvestment Top SP500 2025e Free Cash Flow Yield1 Returning Value to Shareholders Note: See appendix for commodity price assumptions and non-GAAP reconciliations and definitions. Dividends shown are declared dividends within the year, not cash paid. Share repurchases shown are on cash basis, which excludes 1% excise tax and any shares that settled after the quarter-end. 2025 annual dividends = YTD 2025 declared dividends of $504mm + share count, per cover of 3Q25 10Q * $0.22/sh (for remaining quarter of the year). Future dividends are subject to board approval. 1) Source: Factset consensus and market capitalizations. incremental debt reduction, share repurchases, working capital, & leasing 3.5% 3.6% 3.8% 3.9% 4.6% 4.8% 5.4% 5.5% 7.2% 8.4% 11.0%
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$65 $57 $39 $68 $94 $78 $76 $65 $3.12 $2.62 $2.08 $3.91 $6.64 $2.72 $2.29 $3.41 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $- $250 $750 $- $500 $500 $750 $750 $98 $2,000 $400 3.8% 3.9% 4.4% 5.6% 5.4% 5.9% 0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0 500 1000 1500 2000 2500 Liquidity 9/30/25 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2055 senior notes term loans (variable rate interest) interest rates for senior notes Liquidity & Debt Maturity Profile 14 Prioritizing Financial Flexibility Note: See appendix for non-GAAP reconciliations and definitions. Commodity prices are trailing-twelve-month benchmark prices.1) Net debt to pro forma adjusted EBITDAX for the trailing twelve months. History of Conservative Net Leverage WTI HH Conservative debt balance, low rates, & long-dated maturities with substantial liquidity Target <1x Net Leverage for maximum flexibility through all price cycles $mm and average rates Cash & equiv. Repaid $600 million of our $1.0 billion of term loans issued earlier in the year, associated with the Delaware Basin acquisition Revolver availability 0.7x 1.0x 1.6x 0.6x 0.2x 0.3x 0.4x 0.8x - 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 12/31/18 12/31/19 12/31/20 12/31/21 12/31/22 12/31/23 12/31/24 9/30/2025 PF (1)
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Differentiated by Culture, Asset Quality, Inventory Duration, & Commodity Mix Defensively positioned and resilient through commodity cycles 15 Coterra’s Business Strategy • Culture of Excellence Open, non-siloed organization drives internal debate in which the best ideas prevail • Data Driven Approach to Problem Solving Rigorous scientific and financial analysis • Technical Teams Driving Value Creation Leveraging AI and custom applications to generate differentiated results • Iterative Planning Leads to Improved Outcomes Flexibility is key to maximizing value • Conservative and Disciplined Financial Approach Focused on long-term value creation Note: See appendix for non-GAAP reconciliations and definitions. 1) Annualized 3Q25 declared dividend divided by October 30, 2025 share price. Compelling Investment Thesis • Consistent, Profitable Growth & Low Reinvestment Highly capital-efficient portfolio and development program • High-Quality Inventory Long-lived, high-return inventory provides competitive advantage • Diversified Portfolio Provides Ability to Pivot Ability to redirect capital across commodities and asset footprint • Durable Free Cash Flow Driven by balanced oil and natural gas production mix and price exposure • Attractive Shareholder Returns 3.8% dividend yield1 and opportunistic share repurchases • Peer-Leading Balance Sheet Low leverage, high liquidity and a prudent maturity profile
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16 2025e capex in $ millions 2025 Program Key Highlights 2025e Development Program Key Highlights Note: “other” capex includes midstream, saltwater disposal, and infrastructure spend. 1) Defined as capex as % of DCF. See appendix for non-GAAP reconciliations and definitions and commodity price assumptions. Disciplined Capital Program Currently expect ~$2.3 billion of 2025e capex ~55% reinvestment rate1 $1,570 $1,520 $1,560 $250 $350 $320 $230 $230 $230 $200 $200 $200 $2,250 $2,300 $2,310 February Guidance August Guidance Updated Guidance Permian D&C Marcellus D&C Anadarko D&C Other Permian in-line with February guidance Currently running 9 rigs & 3 crews Marcellus +$70mm vs. February guidance Picked up activity through the year Anadarko 3-mile well project (5 net wells) came online 4Q25
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Permian Asset Overview – 2025 Operational Outlook 171) Based on 2025e completed, operated wells. 2) Includes non-op. Note: Spend for a well is incurred over a period of 6-12 months, which does not necessarily fall within a single calendar year. $ per foot includes drilling, completion, facilities and post-completion capital $1,560 million Midpoint D&C CapEx $950 Avg. Well Cost per Foot1 ~165 Net Wells Online2 10,200' Avg. Lateral Length1 Coterra Acreage -10% cost reduction YoY
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$860 $800 $750 $845 $885 $180 $150 $1,040 $950 CTRA 2024 fully-burdened well cost CTRA 2025e fully-burdened well cost Peer A D&C only Peer B D&C only Peer C DC&E Facilities & post-completion Drilling & completion cost, unless otherwise noted for peers in x-axis 18 Top-Tier Delaware Producer with Competitive D&C Well Costs 1) Source: Enverus Prism for historical data and internal forecasts for future estimates. Filtered to >8,500’ laterals. Includes all historical wells from the Franklin Mountain Energy and Avant acquisitions. 2) Sourced from recent company disclosure. CTRA D&C cost estimate based on 2025e completed, operated wells. Peers A, B, and C are companies that publish Delaware Basin well costs. Delaware Productivity1 cumulative 2-stream at 20:1 conversion ratio, boe per lateral foot ‒ Productivity will differ from year to year, depending on project selection & other operational decisions ‒ Generally, our Permian program will be ~1/2 Texas and ~1/2 New Mexico driven by our large, contiguous positions in Culberson County, Texas and Lea County, New Mexico ‒ Our program continues to benefit from optimized spacing and completion design decisions that generate resilient returns at various commodity prices Recent Delaware D&C Well Costs per Foot2 CTRA well costs are fully-burdened 0 10 20 30 40 50 60 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 major peer operator 2022-2024 CTRA 2022-2024 CTRA 2025e-2027e
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Marcellus Asset Overview – 2025 Operational Outlook 19 $320 million Midpoint D&C CapEx $790 Avg. Well Cost per Foot1 9-13 Net Wells Online 17,000' Avg. Lateral Length1 1) Based on 2025e completed, operated wells. Note: Spend for a well is incurred over a period of 6-10 months, which does not necessarily fall within a single calendar year. $ per foot includes drilling, completion, facilities and post-completion capital. -24% cost reduction YoY Coterra Acreage ~30% Upper & ~70% Lower using modeled model is based on “official well
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Anadarko Asset Overview – 2025 Operational Outlook 20 $230 million Midpoint D&C CapEx $1,060 Avg. Well Cost per Foot1 20 Net Wells Online2 11,370' Avg. Lateral Length1 1) Based on 2025e completed, operated wells. Note: Spend for a well is incurred over a period of 6-10 months, which does not necessarily fall within a single calendar year. $ per foot includes drilling, completion, facilities and post-completion capital. 2) Includes non-op. -15% cost reduction YoY Coterra Acreage
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Appendix
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22 High-Quality, Long-Life, Diversified Asset Portfolio 1) Assumes average 2025e-2027e D&C spend and $75 WTI & $3.75 Henry Hub. 2) Meaning FCF covers base dividend for multiple years. See appendix for non-GAAP reconciliations and definitions. 3) D&C Capital = Drilling & Completion Capital, which includes drilling, completion, facilities and post-completion capital. Multi-Basin Portfolio provides commodity diversification and capital allocation optionality Top-Tier Acreage Position with deep inventory, estimated at ~15 years1 Low-Cost Operator with corporate break-even2 around $50/bbl WTI & $2.50/mmbtu HH Production 6:1 Revenue ANADARKO ~181,000 net acres 3Q25 Production: 88 MBoe/d, 44% Liquids 2025e D&C Capital3: $230MM MARCELLUS ~186,000 net acres 3Q25 Production: 1,978 MMcf/d 2025e D&C Capital3: $320MM PERMIAN ~346,000 net acres 3Q25 Production: 367 MBoe/d, 72% Liquids 2025e D&C Capital3: $1,560MM 3Q25 Commodity Splits 61% 21% 17% natural gas oil NGL 30% 57% 12%
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25% 23% 10% 7% 4% 15% 6% 7% 1% 1% Zone 6 NNY NYMEX power in-basin fixed price in-basin Houston Ship Channel in-basin fixed price NYMEX MarcellusPermianAnadarko 87% 62% 61% 61% 97% 73% 71% 74% 65% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% 1Q 2Q 3Q 4Q 2021-2024 range for total company 2025 total company 2025 Marcellus 2025 total company post-hedge 23 Diversified Gas Marketing Portfolio Note: Marcellus primarily first-of-month pricing while Anadarko & Permian are primarily Gas Daily Average pricing.1) Pre-hedge price realizations depicted. MMBtu converted at 1.03 multiplier for Mcf value. See guidance tables for benchmark price assumptions. 2025 Estimated Natural Gas Sales Markets 2021-2025e Natural Gas Price Realization Range1 Gas price realizations differ quarter-to-quarter due to seasonality, and can vary year-to-year with shifts in contract mix / sales markets Additionally, lower benchmark price may trigger contract floors in the Marcellus, raising % realization NYMEX pricing mitigates regional basis exposure % of Henry Hub1 Premium winter pricing Premium pricing to in-basin Accessing gulf-coast pricing Basis fundamentals support strong in-basin pricing
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$1,560 Total Permian Lea County Culberson County Reeves County Eddy County 24 2025e mid-point D&C capex in $ millions 2025e net wells online 2025 Permian Development Program Note: See appendix for non-GAAP reconciliations and definitions. D&C costs and $ per foot estimates include drilling, completion, facilities and post-completion costs. Leading edge $ per foot estimates: $1,020 per foot $830 per foot $1,020 per foot $1,040 per foot Primary target formations: Upper Wolfcamp & Bone Spring Upper Wolfcamp Upper Wolfcamp Lower Wolfcamp & Bone Spring 165 Total Permian Lea County Culberson County Reeves County Eddy County
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Guidance & Actuals 25Note: See appendix for non-GAAP reconciliations and definitions. Numbers may not sum due to rounding. 3Q25 Actual Low Mid High Low Mid High Low Mid High Low Mid High Total Production (mboed) 710 - 740 - 770 772 - 777 - 782 740 - 765 - 790 785 770 - 790 - 810 Gas (mmcfd) 2,675 - 2,775 - 2,875 2,925 - 2,945 - 2,965 2,750 - 2,825 - 2,900 2,895 2,775 - 2,850 - 2,925 Oil (mbod) 152.0 - 160.0 - 168.0 159.0 - 160.0 - 161.0 158.0 - 163.0 - 168.0 166.8 172.0 - 175.0 - 178.0 Net operated wells online Marcellus 10 - 13 - 15 9 - 13 4 4 2 - 6 Permian 150 - 158 - 165 165 40 - 45 - 50 38 41 Anadarko 15 - 20 - 25 20 6 6 5 $ millions: Incurred Capital Expenditures $2,100 - $2,250 - $2,400 $2,310 $625 - $650 - $675 $658 $530 Marcellus D&C $250 $320 Permian D&C $1,570 $1,560 Anadarko D&C $230 $230 Midstream, saltwater disposal, infrastructure $200 $200 Commodity price assumptions: WTI ($ per bbl) Henry Hub ($ per mmbtu) $ billions: Discretionary Cash Flow $4.3 Incurred Capital Expenditures $2.1 - $2.3 - $2.4 $2.3 Free Cash Flow (DCF - cash capex) $2.0 Updated 2025 Guidance $65 $3.41 2025 Guidance (February) $71 $4.22 $5.0 $2.7 Operations Cash Flow & Investment 4Q25 Guidance3Q25 Guidance
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Expense Guidance & Actuals Expense guidance provided for annual 2025 26 2024 Actual 1Q25 Actual 2Q25 Actual 3Q25 Actual $ per boe, unless noted: Lease operating expense + workovers + region office $2.66 $2.50 - $3.05 - $3.60 $3.21 $3.32 $3.80 Gathering, processing, & transportation $3.94 $3.25 - $3.75 - $4.25 $4.20 $3.81 $3.75 Taxes other than income $1.09 $1.25 - $1.50 - $1.75 $1.43 $1.21 $1.29 General & administrative (excluding stock-based compensation) $0.97 $0.90 - $1.00 - $1.10 $1.13 $1.00 $0.97 Unit Operating Cost $8.66 $7.90 - $9.30 - $10.70 $9.97 $9.34 $9.81 DD&A $7.43 $8.00 - $8.75 - $9.50 $7.53 $8.11 $8.58 Exploration1 $0.10 $0.05 - $0.08 - $0.10 $0.15 $0.07 $0.09 % effective tax rate2 22% 21% 22% 24% 1 Excluding exploratory dry hole costs, includes exploration administrative expense and geophysical expenses 2 Expense Expect no cash taxes in 2H25 2025 Guidance
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Published Sustainability Report on August 4, 2025 27Figures listed above include only Scope 1 Subpart W reportable emissions. 2019 to 2021 figures are based on combined results for Cabot & Cimarex. Subsequent figures, including 2025, are Legacy Coterra only and exclude the assets acquired in January 2025. 2024 Actuals are preliminary and not yet finalized by the EPA.
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Non-GAAP Reconciliations & Definitions 28 Supplemental Non-GAAP Financial Measures (Unaudited): We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and results of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations below that compare GAAP financial measures to non-GAAP financial measures for the periods indicated. We have also included herein certain forward-looking non-GAAP financial measures including, among others, the reinvestment rate, which is defined as capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow (non- GAAP). We believe the reinvestment rate provides investors with useful information on management’s projected use and reinvestment of its future cash flows back in Coterra’s operations. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in assets and liabilities (including future impairments) and cash paid for capital expenditures. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant. Capital expenditures is defined as cash capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs. Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas produced activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures Free Cash Flow is an indicator of a company’s ability to generate cash flow after spending the money required to maintain or expand its asset base and is used by our management for that purpose. Free Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flow from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Three Months Ended: 30-Sep Twelve Months Ended: Dec 31 ($ in millions) 2025 ($ in millions) 2024 Cash flow from operating activities 971$ Cash flow from operating activities 2,795$ Changes in assets and liabilities 177 Changes in assets and liabilities 173 Discretionary cash flow 1,148 Discretionary cash flow 2,968 Cash paid for capital expenditures for drilling, completion and other fixed asset additions (615) Cash paid for capital expenditures for drilling, completion and other fixed asset additions (1,754) Free cash flow 533$ Free cash flow 1,214$ Three Months Ended: 30-Sep Twelve Months Ended: Dec 31 ($ in millions) 2025 ($ in millions) 2024 Cash capital expenditures for drilling, completion and other fixed asset additions $615 Cash capital expenditures for drilling, completion and other fixed asset additions $1,754 Change in accrued capital costs 43 Change in accrued capital costs 8 Exploratory dry-hole cost - Capital expenditures $1,762 Capital expenditures $658
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Non-GAAP Reconciliations & Definitions 29 EBITDAX EBITDAX is defined as net income plus interest expense, other expense, income tax expense and benefit, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, earnings and loss on equity method investments, equity method investment distributions, stock-based compensation expense and merger-related costs. EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses EBITDAX for that purpose. EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. The Combined EBITDAX calculations below reflect legacy Cabot and Cimarex results through September 30, 2021 and Coterra results thereafter. Legacy Cimarex operated under the full cost accounting method, unlike legacy Cabot, now Coterra, which operates under the successful efforts accounting method. This difference in accounting methodologies leads to differences in the calculation of company financials and the figures below should not be relied on to predict future performance of the combined business, which operates under the successful efforts accounting method. Net Debt and Net Debt to EBITDAX (or Net Leverage) Net Debt is calculated by subtracting cash and cash equivalents from total debt. Net Debt is a non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire debt. Our management uses this measures for that purpose. Other Defined Terms Present Value Index (PVI10) is often used by management as a return-on-investment metric and defined as the estimated net present value (using a 10% discount rate) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs), adding back our direct net costs incurred in drilling and adding back our completing, constructing facilities, and flowing back such wells, and then dividing that sum by our direct net costs incurred in drilling, completing, constructing facilities, and flowing back such wells. Twelve Months Ended: September 30 ($ in millions) 2025 2024 2023 2022 2021 2020 2019 2018 Net income 1,646$ 1,121$ 1,625$ 4,065$ 1,158$ 201$ 681$ 557$ Plus (less): Interest expense, net 62 54 55 73 Interest expense 185 106 73 80 Interest income (23) (62) (47) (10) (Gain) loss on debt extinguishment (28) - - - - Other expense (benefit) (1) (2) - - 1 - Income tax expense (benefit) 400 224 503 1,104 344 41 219 141 Depreciation, depletion and amortization 2,190 1,840 1,641 1,635 693 391 406 417 Exploration 27 25 20 29 18 15 20 114 (Gain) loss on sale of assets (5) (3) (12) 1 2 0 1 16 Non-cash loss (gain) on derivative instruments (74) 101 54 (299) (210) (26) 58 (86) (Earnings) loss on equity method investments - - - - - 0 (80) (1) Equity method investment distributions - - - - - - 17 - Stock-based compensation 62 62 59 86 57 43 31 33 Severance expense - - 12 62 46 - 3 - Merger-related costs 15 - - 7 72 - - - EBITDAX 4,422$ 3,414$ 3,928$ 6,730$ 2,242$ 719$ 1,412$ 1,264$ Legacy Cimarex EBITDAX 1,005 935 1,460 1,558 Combined EBITDAX 4,422$ 3,414$ 3,928$ 6,730$ 3,247$ 1,654$ 2,872$ 2,822$ September 30 ($ in millions) 2025 2024 2023 2022 2021 2020 2019 2018 Total debt $3,922 $3,535 $2,161 $2,181 $3,125 $3,134 $3,220 $2,726 Less: Cash and cash equivalents (98) (2,038) (956) (673) (1,036) (413) (295) (803) Less: Short-term investments Net debt $3,824 $1,497 $1,205 $1,508 $2,089 $2,721 $2,925 $1,923 TTM EBITDAX $4,422 $3,414 $3,928 $6,730 $3,247 $1,654 $2,872 $2,822 Net debt to TTM EBITDAX 0.9x 0.4x 0.3x 0.2x 0.6x 1.6x 1.0x 0.7x December 31 Combined Cabot + Cimarex Combined Cabot + Cimarex December 31 Coterra Coterra
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Non-GAAP Reconciliations & Definitions 30 Adjusted Pro Forma EBITDAX (trailing twelve months) Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma interest income, pro forma income tax expense, pro forma depreciation, depletion, and amortization (including impairments), pro forma exploration expense, pro forma gain and loss on sale of assets, pro forma non-cash gain and loss on derivative instruments, pro forma acquisition-related expenses, and pro forma stock-based compensation expense. Adjusted Pro Forma EBITDAX represents the effects of the Franklin Mountain Energy and Avant Natural Resources acquisitions as if they had occurred on January 1, 2024. Adjusted Pro Forma EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt after the acquisitions without regard to financial or capital structure. Our management uses Adjusted Pro Forma EBITDAX for that purpose. Adjusted Pro Forma EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, pro forma net income or net income, as defined by GAAP, or as a measure of liquidity. Net Debt to Adjusted Pro Forma EBITDAX Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted Pro Forma EBITDAX is defined as net debt divided by trailing twelve month Adjusted Pro Forma EBITDAX. Net debt to Adjusted Pro Forma EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage. Trailing Twelve Months Ended: September 30 December 31 ($ in millions) 2025 2024 Pro forma net income 1,762$ 1,475$ Plus (less): Pro forma interest expense 224 250 Pro forma interest income (23) (62) Pro forma other income (1) - Pro forma income tax expense 411 297 Pro forma depreciation, depletion and amortization 2,314 2,195 Pro forma exploration 27 25 Pro forma gain on sale of assets (5) (3) Pro forma non-cash loss on derivative instruments (74) 101 Pro forma acquisition-related expenses 15 15Pro forma stock-based compensation 62 62 Adjusted Pro Forma EBITDAX (trailing twelve months) 4,712$ 4,355$ September 30 December 31 ($ in millions) 2025 2024 Net debt (as defined previously) 3,824$ 1,497$ Adjusted Pro Forma EBITDAX (Trailing twelve months) 4,712 4,355 Net debt to Adjusted EBITDAX 0.8x 0.3x