Coterra Energy Inc. · NYSE:CTRA
Coterra Energy — Q3 2025 Earnings Presentation
30 slides from Coterra Energy's earnings presentation, Nov 4, 2025
Slide 1: 3Q25 Earnings Presentation
3Q25 Earnings Presentation November 2025
Slide 2: Disclaimer
Disclaimer Cautionary Statement Regarding Forward-Looking Information 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.
Slide 3: Key Takeaways from Third Quarter 2025 Update
Key Takeaways from Third Quarter 2025 Update 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 Looking Ahead to 2026 | Anticipate 2026e c
Slide 4: Beat 3Q25 Midpoint Production Volumes & Raised for the Year
Beat 3Q25 Midpoint Production Volumes & Raised for the Year Higher production & lower capex driving improved capital efficiency 3Q25 actuals vs. guide 2025e guidance update Oil guidance 158.0 168.0 February guid. 152.0 168.0 mbod actual 166.8 updated guid. 159.0 161.0 Gas guidance 2,750 2,900 Februa
Slide 5: Coterra Energy Key Differentiating Factors
Coterra Energy Key Differentiating Factors Asset Competitive Cost Top-Tier Margin & Quality Structure Capital Efficiency Consistent Investment in FCF Durability, Culture & Deep, High-Quality Shareholder Returns, Strategy Inventory Top-Tier Balance Sheet Note: See appendix for non-GAAP reconciliation
Slide 6: Asset Quality Demonstrated by Low Break-Evens
Asset Quality Demonstrated by Low Break-Evens Estimated 15:1 PV-10 Break-Even Oil Price Across L48 Assets1 CTRA vs Peers; 15:1 based on recent strip $50 $46 $46 $45 $43 $43 $42 $42 $43 $42 $42 $41 $40 $40 $39 C TR A Peers include APA, AR, CHRD, CIVI, DVN, EOG, EQT, EXE, FANG, MTDR, OVV, OXY, PR, RRC
Slide 7: Sustained Improvement in Fully Burdened Well Costs, Enhancing Economics
Sustained Improvement in Fully Burdened Well Costs, Enhancing Economics Driven by longer laterals and efficient operations Annual Average Well Cost per Foot1 $1,290 $1,260 $1,130 $1,150 $1,100 $1,090 $1,060 $1,060 $1,020 $1,020 $940 $950 $890 $910 $790 $770 -13% -21% -21% -30% 2023 2024 2025e 2026e
Slide 8: CTRA's High Quality Assets Produce Top-Tier Margins
CTRA’s High Quality Assets Produce Top-Tier Margins CTRA Margin Consistently ~65-70% 2026e Revenue per BOE vs Margin Recent strip: Henry Hub of $4.02/mmbtu & WTI of $60/bbl revenue/boe EBITDA/boe % margin 2026e revenue/boe 2026e % margin - right axis $16 100% $30 80% 90% 71% 71% $14 70% 70% $25 67%
Slide 9: 2025: Top-Tier Capital Efficiency Paired with Industry-Leading Growth
2025: Top-Tier Capital Efficiency Paired with Industry-Leading Growth Coterra has one of the highest growth rates with best-in-class capital efficiency 2025e Operational and Financial Outlook 2025e Capital Efficiency and 2026e Production Growth 2025e capital efficiency average capital efficiency con
Slide 10: Disciplined Approach to Capital Investment
Disciplined Approach to Capital Investment Differentiated reinvestment rate through the commodity cycles Conservative historical reinvestment rate Low reinvestment among peers in 2026 gas-weighted peers oil-weighted peers CTRA gas peer average oil peer average CTRA average 70% 95% 87% 60% 85% 50% 77
Slide 11: Long Runway of High-Quality Inventory
Long Runway of High-Quality Inventory Benchmark price assumptions of $75/bbl and $3.75/mmbtu ~$31 billion of Economic Capex Opportunities Implied Inventory Duration1 estimated capex by PVI10 bucket: estimated total footage by asset area: estimates can fluctuate based on assumptions around well spaci
Slide 12: Durable Free Cash Flow Through the Cycles
Durable Free Cash Flow Through the Cycles Oil-to-gas price ratios can, and have historically decoupled, especially during periods of extreme volatility Uniquely positioned to weather volatility Resilient Future Free Cash Flow & disciplined Diversified commodity portfolio with demonstrated capital fl
Slide 13: Returning Value to Shareholders
Returning Value to Shareholders Free Cash Flow in $ millions Top SP500 2025e Free Cash Flow Yield1 YoY increase driven by greater oil volumes from Lea County acquisition, higher gas price, and disciplined reinvestment 11.0% FCF annual dividends share repurchases to date debt repayments to date 8.4%
Slide 14: Prioritizing Financial Flexibility
Prioritizing Financial Flexibility History of Conservative Net Leverage Liquidity & Debt Maturity Profile WTI HH $mm and average rates senior notes term loans (variable rate interest) interest rates for senior notes $8.00 $94 2500 0.07 $7.00 $6.64 $78 $76 $6.00 $65 $68 $65 0.06 $5.00 5.9% $57 2000 5
Slide 15: Differentiated by Culture, Asset Quality, Inventory Duration, & Commodity Mix
Differentiated by Culture, Asset Quality, Inventory Duration, & Commodity Mix Defensively positioned and resilient through commodity cycles Coterra’s Business Strategy Compelling Investment Thesis • Culture of Excellence • Consistent, Profitable Growth & Low Reinvestment Open, non-siloed organizatio
Slide 16: 2025e Development Program Key Highlights
2025e Development Program Key Highlights 2025e capex in $ millions 2025 Program Key Highlights Permian D&C Marcellus D&C Anadarko D&C Other Permian in-line with February guidance $2,250 $2,300 $2,310 Currently running 9 rigs & 3 crews $200 $200 $200 $230 $230 $230 $250 $350 $320 Marcellus +$70mm vs.
Slide 17: Permian Asset Overview – 2025 Operational Outlook
Permian Asset Overview – 2025 Operational Outlook Coterra Acreage $1,560 million Midpoint D&C CapEx 10,200' $950 ~165 Avg. Lateral Avg. Well Cost Net Wells Length1 per Foot1 Online2 -10% cost reduction YoY 1) Based on 2025e completed, operated wells. 2) Includes non-op. Note: Spend for a well is inc
Slide 18: Top-Tier Delaware Producer with Competitive D&C Well Costs
Top-Tier Delaware Producer with Competitive D&C Well Costs Delaware Productivity1 Recent Delaware D&C Well Costs per Foot2 cumulative 2-stream at 20:1 conversion ratio, boe per lateral foot Facilities & post-completion major peer operator 2022-2024 CTRA 2022-2024 Drilling & completion cost, unless o
Slide 19: Marcellus Asset Overview – 2025 Operational Outlook
Marcellus Asset Overview – 2025 Operational Outlook Coterra Acreage $320 million Midpoint D&C CapEx 17,000' $790 9-13 Avg. Lateral Avg. Well Cost Net Wells Length1 per Foot1 Online -24% ~30% Upper & cost reduction YoY ~70% Lower 1) Based on 2025e completed, operated wells. Note: Spend for a well is
Slide 20: Anadarko Asset Overview – 2025 Operational Outlook
Anadarko Asset Overview – 2025 Operational Outlook Coterra Acreage $230 million Midpoint D&C CapEx 11,370' $1,060 20 Avg. Lateral Avg. Well Cost Net Wells Length1 per Foot1 Online2 -15% cost reduction YoY 1) Based on 2025e completed, operated wells. Note: Spend for a well is incurred over a period o
Slide 21: Appendix
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Slide 22: High-Quality, Long-Life, Diversified Asset Portfolio
High-Quality, Long-Life, Diversified Asset Portfolio 3Q25 Commodity Splits Multi-Basin Portfolio natural gas oil NGL provides commodity diversification and capital ANADARKO 17% allocation optionality ~181,000 net acres 3Q25 Production: 88 MBoe/d, 44% Liquids MARCELLUS Production 6:1 2025e D&C Capita
Slide 23: Diversified Gas Marketing Portfolio
Diversified Gas Marketing Portfolio 2025 Estimated Natural Gas Sales Markets 2021-2025e Natural Gas Price Realization Range1 % of Henry Hub1 2021-2024 range for total company 2025 total company Zone 6 NNY 25% Premium winter pricing 2025 Marcellus 2025 total company post-hedge 100% NYMEX 23% NYMEX pr
Slide 24: 2025 Permian Development Program
2025 Permian Development Program 2025e mid-point D&C capex in $ millions 2025e net wells online 165 $1,560 Total Permian Lea County Culberson County Reeves County Eddy County Total Permian Lea County Culberson County Reeves County Eddy County Leading edge Primary target Upper Upper Upper Lower $ per
Slide 25: Guidance & Actuals
Guidance & Actuals 2025 Guidance (February) Updated 2025 Guidance 3Q25 Guidance 3Q25 Actual 4Q25 Guidance 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 -
Slide 26: Expense Guidance & Actuals
Expense Guidance & Actuals Expense guidance provided for annual 2025 2024 Actual 2025 Guidance 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 $3.94
Slide 27: Published Sustainability Report on August 4, 2025
Published Sustainability Report on August 4, 2025 Figures listed above include only Scope 1 Subpart W reportable emissions. 2019 to 2021 figures are based on combined results for Cabot & Cimarex. Subsequent figures, including 2025, are Legacy Coterra only and exclude the assets acquired in January 2
Slide 28: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions Supplemental Non-GAAP Financial Measures (Unaudited): We report our financial results in accordance with accounting Three Months Ended: 30-Sep Twelve Months Ended: Dec 31 principles generally accepted in the United States (GAAP). However, we believe certain non
Slide 29: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions EBITDAX Twelve Months Ended: ($ in millions) September 30 2025 2024 2023 December 31 2022 2021 2020 2019 2018 EBITDAX is defined as net income plus interest expense, other expense, income tax expense and benefit, Coterra Combined Cabot + Cimarex depreciation, d
Slide 30: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions Adjusted Pro Forma EBITDAX (trailing twelve months) Trailing Twelve Months Ended: September 30 December 31 ($ in millions) 2025 2024 Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma interest income, pro fo