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Coterra Energy Inc. (CTRA) Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 delivered an EPS beat: Adjusted EPS was $0.48 vs Wall Street consensus $0.45*, while GAAP EPS was $0.67 . EBITDA materially outperformed at $1.283B vs $1.063B consensus*.
  • Revenue was mixed depending on definition: S&P “Revenue” was $1.665B vs $1.686B consensus (slight miss)*; GAAP operating revenues totaled $1.965B, boosted by a $232M non‑cash derivatives gain .
  • Guidance tightened and raised: full‑year total equivalent and natural gas production midpoints were increased; oil midpoint maintained; Q3 guide issued with 740–790 MBoepd and capex $625–$675M .
  • Capital discipline remained a catalyst: $0.22 dividend declared; $23M buybacks; $100M term loan repayment; management reiterated prioritizing deleveraging with intent to retire remaining $650M of term loans in 2025 .

Values marked with * retrieved from S&P Global.

What Went Well and What Went Wrong

What Went Well

  • Production outperformance: Total equivalent volumes of 783.9 MBoepd exceeded the high end of guidance; natural gas beat the high end; oil was near the high end .
    Quote: “We exceeded the high end of our guidance range for natural gas and total…BOE… and came in well above our midpoint on oil volumes.” — CEO Tom Jorden .
  • Capex efficiency: Non‑GAAP capex came in at $569M, below the guidance range low end ($575M–$650M), driving strong reinvestment efficiency .
  • Balance sheet and FCF: Cash from operations was $937M; Free Cash Flow was $329M; net debt remained ~1.0x TTM Adjusted EBITDAX with further term loan repayments targeted .
    Quote: “We are quickly executing on getting our leverage back…around 0.5x net debt to EBITDA.” — CFO Shane Young .

What Went Wrong

  • Revenue under S&P definition: $1.665B came in just below the $1.686B consensus*, despite GAAP operating revenues being higher due to a non‑cash derivatives gain .
  • Unit costs vs prior year: Unit operating cost was $9.34/BOE, higher than Q2 2024 ($8.35/BOE), reflecting mix and activity, though down 6% QoQ on volumes .
  • Harkey mechanical issues: Culberson Harkey wells required remediation; while progress was positive and new adjacent Harkey wells met/exceeded expectations, management removed the volumes from near‑term guidance .

Values marked with * retrieved from S&P Global.

Financial Results

Actual vs S&P Global Consensus (Q2 2025)

MetricConsensusActual
Adjusted EPS ($)0.45*0.48*
Revenue ($USD Billions)1.686*1.665*
EBITDA ($USD Billions)1.063*1.283*

Values retrieved from S&P Global.

Income Statement, Cash Flow, Costs (Chronological: Q2 2024 → Q1 2025 → Q2 2025)

MetricQ2 2024Q1 2025Q2 2025
Operating Revenues ($USD Billions)$1.271 $1.904 $1.965
GAAP EPS ($)$0.30 $0.68 $0.67
Adjusted EPS ($)$0.37 $0.80 $0.48
Net Income ($USD Millions)$220 $516 $511
Cash Flow from Ops ($USD Millions)$558 $1,144 $937
Free Cash Flow ($USD Millions)$246 $663 $329
Capital Expenditure (non‑GAAP) ($USD Millions)$477 $552 $569
Unit Operating Cost ($/BOE)$8.35 $9.97 $9.34

Commodity Revenue Breakdown (YoY)

Revenue Component ($USD Millions)Q2 2024Q2 2025
Oil$774 $888
Natural Gas$319 $601
NGL$176 $219
Other$18 $25
Gain (Loss) on Derivatives$(16) $232
Operating Revenues (total)$1,271 $1,965

Production and Costs (Chronological: Q2 2024 → Q1 2025 → Q2 2025)

KPIQ2 2024Q1 2025Q2 2025
Total Equivalent Production (MBoepd)669.2 746.8 783.9
Oil Production (MBopd)107.2 141.2 155.4
Natural Gas (MMcfpd)2,779.8 3,043.8 2,998.6
NGL Production (MBopd)98.8 98.3 128.7
Unit Operating Cost ($/BOE)$8.35 $9.97 $9.34

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Total Equivalent Production (MBoed)FY 2025720–745–770 755–768–780 Raised midpoint
Natural Gas (Bcf/d)FY 20252.725–2.800–2.875 2.875–2.913–2.950 Raised midpoint
Oil (MBopd)FY 2025155–160–165 157–160–163 Maintained midpoint
Capital Expenditures (non‑GAAP) ($B)FY 2025$2.0–$2.3 $2.1–$2.3 (expect ~$2.3) Low end raised; tightened
Effective Tax RateFY 2025N/A~22%; current tax 40–60% New
Total Equivalent Production (MBoepd)Q3 2025N/A740–790 New
Oil (MBopd)Q3 2025N/A158–168 New
Natural Gas (Bcf/d)Q3 2025N/A2.75–2.90 New
Capital Expenditures (non‑GAAP) ($M)Q3 2025N/A$625–$675 New
Dividend per share ($)Q2 2025$0.22 declared Q1 $0.22 declared Q2 Maintained

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2024 & Q1 2025)Current Period (Q2 2025)Trend
Gas marketing diversification (power/LNG/data centers)Re‑engaging power and LNG; exploring data center power; two Marcellus power deals; pursuing Permian opportunities Announced Permian power netback deal with CPV Basin Ranch (50 MMcf/d from 2028; ERCOT‑indexed) and right to purchase up to 250 MW; portfolio diversification emphasized Accelerating
Culberson Harkey remediationIdentified mechanical/cement isolation issues; paused local Harkey; pivoted to Upper Wolfcamp; reaffirmed 3‑year plan New adjacent Harkey wells near Wyndham Row meeting/exceeding expectations; remediation ongoing; volumes excluded from guidance Improving execution
Capital allocation & reinvestmentFlexibility across basins; reinvestment ~50%; potential gas add; debt repayment priority Reinvestment ~50% with steady cadence; Q3 capex peak; reaffirm deleveraging and back‑half buybacks Maintained discipline
TaxesInitial outlook 20–25% effective tax; cash taxes high in 2024 2025 effective tax ~22%; 40–60% current tax (minimal current tax H2); later moving to 70–90% Near‑term tailwind
Cost structure & lateral lengths (Marcellus)Reengineered plan; long laterals; $800/ft cost; Upper Marcellus competitive Continued long laterals; strong production from “box” wells; plan to add 7–12 TILs into winter Sustained improvement
Macro volatility (tariffs, OPEC+ curtailments)Flexibility to pivot; cautious stance Management highlighted commodity uncertainty; keeping steady crew cadence; 9 Permian rigs, 2 Marcellus, 1–2 Anadarko Stable cadence

Management Commentary

  • “We exceeded the high end of our guidance range for natural gas and total…BOE… and came in well above our midpoint on oil volumes.” — CEO Tom Jorden .
  • “It was one of the highest yielding base dividends in the industry at over 3.5%… we remain committed to reviewing increases to the base dividend on an annual basis.” — CFO Shane Young .
  • “Announcing a new power netback gas sale agreement… 50 MMcf per day for a seven‑year term… indexed to ERCOT West pricing… first power netback deal in the Permian Basin.” — 8‑K/Press Release .
  • “We are quickly executing on getting our leverage back… around 0.5x net debt to EBITDA… expect to fully repay the remaining $650,000,000 of term loans during 2025.” — CFO Shane Young .

Q&A Highlights

  • Harkey remediation: Mechanical isolation and cement design adjustments; adjacent Harkey wells performing strongly; remediation volumes conservatively excluded from guidance .
  • Oil trajectory: High confidence in H2 ramp driven by high working‑interest projects; Q4 “stair‑step” trajectory; Q1 not expected to exceed Q4 .
  • Gas strategy: Will reallocate molecules from in‑basin Waha into diversified power/LNG sales; curtailments and delayed completions remain in the toolkit if pricing deteriorates .
  • Buybacks vs deleveraging: Term loan repayment prioritized in 2025; opportunistic buybacks back‑half weighted; target 75–100% of FCF returns once deleveraged .
  • Taxes: Benefit from 100% bonus depreciation and R&D expensing; minimal current taxes in H2 2025; current tax percentage rising to 70–90% over time .

Estimates Context

  • Adjusted EPS beat: $0.48 actual vs $0.45 consensus*.
  • Revenue slight miss under S&P definition: $1.665B actual vs $1.686B consensus*; GAAP operating revenues were $1.965B due to non‑cash derivatives gain .
  • EBITDA beat: $1.283B actual vs $1.063B consensus*.
  • Consensus recommendation (text) was unavailable in S&P data.
    Values retrieved from S&P Global.

Key Takeaways for Investors

  • EPS and EBITDA beats, with production outperformance and capex below plan, reinforce capital efficiency and free cash flow durability .
  • Near‑term stock catalysts include Q3 guide execution, progress on Harkey remediation (already derisked in guidance), and visible deleveraging trajectory to retire remaining term loans in 2025 .
  • Revenue “miss” under S&P reflects accounting definitions; GAAP operating revenues benefited from a sizable non‑cash derivatives gain; focus on cash metrics and adjusted EBITDAX for core performance .
  • Diversified gas marketing is a strategic upside lever: new ERCOT‑indexed power netback in the Permian and existing PJM power deals mitigate Waha basis and add pricing optionality into 2026–2028 .
  • Watch cost trajectory: unit operating cost improved QoQ on volumes; sustained long‑lateral Marcellus program and Permian efficiencies should continue to support reinvestment ~50% .
  • Guidance momentum: FY midpoints raised for BOE and gas; Q3 capex peak supports H2 volume stair‑step; oil midpoint held steady despite macro volatility .
  • Capital returns set to expand post‑deleveraging; expect buyback pace to increase as term loans are retired, with one of the sector’s higher base yields maintained .

Citations: .

Values marked with * retrieved from S&P Global.

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