Coterra Energy Inc. · NYSE:CTRA
Coterra Energy — Q1 2025 Earnings Presentation
37 slides from Coterra Energy's earnings presentation, May 6, 2025
Slide 1: 1Q25 Earnings Presentation
1Q25 Earnings Presentation May 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: Coterra Energy – A Differentiated Oil & Natural Gas Company
Coterra Energy – A Differentiated Oil & Natural Gas Company Consistent, Profitable Growth Through the Commodity Cycles Who Is Coterra? Why Own Coterra? • Culture of Excellence • Consistent, Profitable Growth & Low Reinvestment Open, non-siloed organization drives internal debate in which the Highly
Slide 4: 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 Free Cash Flow Through Volatile Diversified Commodity Portfolio with Demonstrated Capital Flexib
Slide 5: 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 2025 oil-weighted peers CTRA gas peer average oil peer average 70% gas-weighted peers 85% 80% 60% 78% 75% 50% 2025 reinve
Slide 6: Improving 2025 Production Guide at Lower Capital
Improving 2025 Production Guide at Lower Capital Lowering 2025 Capital Range to $2.0-$2.3bn | Reallocating Investment From Permian Oil to Marcellus Gas | Increasing BOE and Natural Gas Production Midpoint Strong 1Q25 Results | Beat the mid-point of oil production, BOE production, and capex guidance
Slide 7: Beat Midpoint of 1Q25 Production Guidance & Updating Annual Guidance
Beat Midpoint of 1Q25 Production Guidance & Updating Annual Guidance Higher production & lower capex driving improved capital efficiency 1Q25 2025e Oil guidance 134.0 144.0 February guid. 152.0 168.0 mbod actual 141.2 updated guid. 155.0 165.0 Gas guidance 2,850 3,000 February guid. 2,675 2,875 mmcf
Slide 8: 2025 Capital Down from February Guide
2025 Capital Down from February Guide Lowering annual capital $100mm: increasing natural gas investment $50 million, decreasing oil investment $150 million 2025e Capex Summary Capex Walk From February Guidance $ millions on y-axis Disciplined Capital Program $2.0 to $2.3 billion capex & ~50% reinves
Slide 9: Committed to Capital Discipline & Free Cash Flow Generation
Committed to Capital Discipline & Free Cash Flow Generation Expect to reinvest ~50-60% of discretionary cash flow at mid-cycle prices $ billions on y-axis | benchmark prices on x-axis capex as % of DCF $6 61% $5 59% 58% $4 45% $3 DCF $4.8 $2 DCF DCF capex capex capex capex $2.2 $3.7 $2.2 $3.4 $2.1 D
Slide 10: Committed to Returning Value
Committed to Returning Value $ billions | Percentages shown are shareholder returns as percentage of Free Cash Flow 2024 FCF $1.2bn 2025e FCF $2.1bn Returned 89% of FCF to shareholders see appendix for commodity price assumptions • In 2025, intend to utilize FCF for base through dividends & share re
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: Prioritizing Financial Flexibility
Prioritizing Financial Flexibility History of Conservative Net Leverage Liquidity & Debt Maturity Profile WTI HH $mm and average rates $8.00 $94 senior notes term loans (variable rate interest) interest rates for senior notes $7.00 $6.64 $78 $76 $6.00 2500 0.0 $71 $65 $68 $5.00 $57 $3.91 $4.00 0.0 $
Slide 13: Permian Asset Overview – 2025 Operational Outlook
Permian Asset Overview – 2025 Operational Outlook $1,450 million Midpoint D&C CapEx 10,600' $960 150-165 Avg. Lateral Avg. Well Cost Net Wells Length1 per Foot1 Online 1) Based on 2025e operated, completed wells. Note: Spend for a well is incurred over a period of 6-12 months, which does not necessa
Slide 14: Permian Asset Overview
Permian Asset Overview Targeting Prolific Wolfcamp & Bone Spring Notable Projects Culberson County, TX Lea County, NM 5 1. Windham Row Update 4. Red Hills • 73 gross wells (50% WI), across six DSUs • 10 gross wells (78% WI), first prod 3Q25 Capital: D&C $/ft of $850 5. Alpha Wolf • One of the lowest
Slide 15: Permian Well Cost Reductions Expected in 2025, Driven by Ops Efficiencies
Permian Well Cost Reductions Expected in 2025, Driven by Ops Efficiencies $ per foot cost estimates Permian reduction driven by operational efficiencies Synergies on our newly acquired Lea County asset Reduced $ per foot on acquired $1,020 $1,090 assets by ~10% with design optimization & lower servi
Slide 16: 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 CTRA 2025e-2027e Drilling & completi
Slide 17: 2025 Permian Development Program
2025 Permian Development Program 2025e mid-point D&C capex in $ millions 2025e net wells online 150-165 $1,450 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 Upper $
Slide 18: Marcellus Asset Overview – 2025 Operational Outlook
Marcellus Asset Overview – 2025 Operational Outlook $300 million Midpoint D&C CapEx 19,100’ $660 Avg. Lateral Avg. Well Length for Upper1 Cost per Foot1 10-15 14,700’ Net Wells $860 Online Avg. Lateral Avg. Well ~30% Upper & Length for Lower1 Cost per Foot1 ~70% Lower 1) Based on 2025e operated, com
Slide 19: Marcellus Asset Overview
Marcellus Asset Overview Highly capital efficient: ~$450mm annual capex spend maintains ~2 bcfd production levels Susquehanna County acreage leverages highly Reduction in well costs YoY driven by 2025e mid-point D&C capex productive Marcellus significantly longer laterals in $ millions Coterra Acrea
Slide 20: Anadarko Asset Overview – 2025 Operational Outlook
Anadarko Asset Overview – 2025 Operational Outlook $230 million Midpoint D&C CapEx 11,080' $1,070 15-25 Avg. Lateral Avg. Well Cost Net Wells Length1 per Foot1 Online 1) Based on 2025e operated, completed wells. Note: Spend for a well is incurred over a period of 6-10 months, which does not necessar
Slide 21: Anadarko Asset Overview
Anadarko Asset Overview Anadarko sub-regions Coterra Acreage Major 2025 Anadarko projects Project Estimated 60-month production Online Well count Area name mix at 6:1 oil 3% Downdip (Primarily NGL 8.9 net 40% 2Q 2025 Roberts Woodford, (9 gross) gas 1 gross 57% Meramec) DOWNDIP Gas & NGL-Weighted UPD
Slide 22: Anadarko Investment Allocation by Area & Cost Savings
Anadarko Investment Allocation by Area & Cost Savings Wider spacing, longer laterals, and lower well costs are driving improved productivity & higher returns 2025e mid-point D&C capex in $ millions YoY cost savings driven by longer laterals1 $230 $1,300 first 3-mile development coming in 2025 $105 $
Slide 23: Appendix
< (az (az Lu - oO O Appendix
Slide 24: High-Quality, Long-Life, Diversified Asset Portfolio
High-Quality, Long-Life, Diversified Asset Portfolio 1Q25 Commodity Splits natural gas oil NGL Multi-Basin Portfolio provides commodity 13% diversification and capital ANADARKO allocation optionality ~181,000 net acres 1Q25 Production: 71 MBoe/d, 47% Liquids MARCELLUS 19% Production 6:1 2025e D&C Ca
Slide 25: Executive Compensation Tied to Emissions Reduction Metrics
Executive Compensation Tied to Emissions Reduction Metrics 20% of total short-term incentive potential Climate Targets Greenhouse Gas Emissions Intensity In 2024, four climate metrics were included in Coterra’s executive short-term incentive targets. MT CO2e / Gross Mboe Produced These four targets
Slide 26: Emissions Reductions Efforts
Emissions Reductions Efforts • Electrifying compressors, fracs, & drilling rigs • Utilizing Vapor Recovery Units to maximize Greenhouse typically reduces net Scope 1 + Scope 2 emissions Flared revenue and minimize flaring Gas from those sources by 25-45%, depending on the Emissions • Centralizing fl
Slide 27: Upstream Greenhouse Gas Intensity vs. Peers & Industry
Upstream Greenhouse Gas Intensity vs. Peers & Industry GHG Intensity (MT CO2e / Gross Mboe) We analyze our upstream emissions on a standalone basis to compare our performance against our peers1, as our peer group has varying levels of operations within the upstream and midstream segments. The follow
Slide 28: Diversifying Gas Portfolio with New LNG Contracts
Diversifying Gas Portfolio with New LNG Contracts Reducing in-basin price exposure & diversifying toward European and Asian markets with expanding LNG portfolio Contracted Production Pricing LNG Volumes From Index 50 mmcfd Marcellus TTF TTF (NETHERLANDS) NBP (U.K.) 2028 – 2038 LNG terminal in Louisi
Slide 29: Midstream/Power Capability in our Permian Assets
Midstream/Power Capability in our Permian Assets Culberson and NM Lea County TX Cost Savings Reeves Counties Bolt-on Acquisition Saltwater Disposal • Over 300 miles of pipeline, reduces surface storage • ~120 miles of pipeline 30-60% per barrel & potential spills cost savings Allows for substantial
Slide 30: 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 2025e total company 2025e Marcellus Zone 6 NNY (premium to in-basin) 22% 100% Gas price realizations differ quarter-to-quarte
Slide 31: 2025 Hedge Summary
2025 Hedge Summary 2Q25e-4Q25e Remaining 2025e gas volumes ~50% hedged Remaining 2025e oil volumes >40% hedged $3.01/MMBtu & $4.82/MMBtu ~$62/bbl & ~$79/bbl weighted average floor & ceiling price on NYMEX weighted average floor & collars ceiling price on collars ~$69/bbl weighted average on swaps fi
Slide 32: Guidance & Actuals
Guidance & Actuals 2025 Guidance (February) Updated 2025 Guidance 1Q25 Guidance 1Q25 Actual 2Q25 Guidance Low Mid High Low Mid High Low Mid High Low Mid High Total Production (mboed) 710 - 740 - 770 720 - 745 - 770 710 - 730 - 750 747 710 - 735 - 760 Gas (mmcfd) 2,675 - 2,775 - 2,875 2,725 - 2,800 -
Slide 33: Expected 2025 Operational Cadence
Expected 2025 Operational Cadence Rig Activity spot work / not full-time in the quarter Crew Activity spot work / not full-time in the quarter 1Q25 2Q25 3Q25 4Q25 1Q25 2Q25 3Q25 4Q25 Permian 7 full-year rigs Permian 3 full-year crews Anadarko 1 partial-year crew Marcellus 1 partial-year crew 6 parti
Slide 34: Expense Guidance & Actuals
Expense Guidance & Actuals Expense guidance provided for annual 2025 2024 Actual 2025 Guidance 1Q25 Actual $ per boe, unless noted: Lease operating expense + workovers + region office $2.66 $2.50 - $3.05 - $3.60 $3.21 Gathering, processing, & transportation $3.94 $3.25 - $3.75 - $4.25 $4.20 Taxes ot
Slide 35: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions Supplemental Non-GAAP Financial Measures (Unaudited): We report our financial results in accordance with accounting Three Months Ended: 31-Mar Twelve Months Ended: Dec 31 Dec 31 principles generally accepted in the United States (GAAP). However, we believe cert
Slide 36: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions Twelve Months Ended: March 31 December 31 EBITDAX ($ in millions) 2025 2024 2023 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, deple
Slide 37: Non-GAAP Reconciliations & Definitions
Non-GAAP Reconciliations & Definitions Adjusted Pro Forma EBITDAX (trailing twelve months) Trailing Twelve Months Ended: March 31 December 31 ($ in millions) 2025 2024 Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma Pro forma net income $ 1,49