Coterra Energy Inc. (CTRA) Q3 2025 Earnings Summary

Executive Summary

Q3 2025 delivered strong operations with production near the high end of guidance (785.0 MBoepd; oil 166.8 MBopd; gas 2,894.6 MMcf/d) and solid cash generation (Discretionary Cash Flow $1.15B; Free Cash Flow $0.53B) . Adjusted EPS was $0.41 and GAAP EPS $0.42 .
Versus S&P Global consensus, EPS was modestly below ($0.41 vs $0.43 cons) while standardized revenue missed (≈$1.68B vs $1.75B cons); Adjusted EBITDA was roughly in line (≈$1.09B vs $1.09B cons) — see Estimates Context for details and S&P disclaimer.*
FY25 guidance raised/tightened: total equivalent to 772–782 MBoed (from 755–780), gas to 2.925–2.965 Bcf/d (from 2.875–2.950), oil tightened to 159–161 MBopd; Q4 guide: 770–810 MBoed, oil 172–178 MBopd, capex ≈$530M .
Capital returns and balance sheet: $0.22 dividend declared; repaid $250M of term loans in Q3 (now $600M repaid YTD) and resumed buybacks in October; net debt/Adj Pro Forma EBITDAX ~0.8x .
Potential stock catalysts: FY25 production raise and Q4 oil ramp, 2026 “soft” outlook (capex modestly down with 0–5% BOE and ~5% oil growth), and activist pressure following Kimmeridge’s letter urging strategic changes .

What Went Well and What Went Wrong

What Went Well
- Production execution: All streams beat midpoints (~2.5%) and total volumes near the high end of Q3 guidance; 48 net wells turned in-line and DCF/FCF of $1.15B/$0.53B showcased capital efficiency .
- Permian integration: Management cites cost-per-foot down ~10% on acquired assets, LOE run-rate savings targeted at ~15% with microgrids potentially halving power costs, supporting stronger returns in Northern Delaware .
- Long-term positioning: Management reiterated a balanced oil/gas portfolio and expects 2026 capex modestly down while maintaining growth; “Coterra has never been stronger or better positioned” .
- Quote: “We are pleased with our strong operational execution… Our nine rig and three completion crew program in the Permian… is generating strong returns at today’s prevailing prices” .
What Went Wrong
- Unit costs ticked up: Q3 unit operating cost rose to $9.81/boe (from $9.34 in Q2) on mix and workovers; mgmt expects Q4 to trend toward the annual midpoint .
- Permian TILs slightly light vs guide: 38 net TILs vs 40–50 guided, pushing activity into Q4, though overall annual ranges still expected to be met .
- Waha exposure headwind: Weak Waha gas prices weighed on realizations; company is pursuing long-haul pipes and in-basin power netbacks to improve basis/price .
- Activist overhang: Kimmeridge’s letter criticized governance and strategy, advocating a Permian pure-play focus; management acknowledged the letter but emphasized multi-basin benefits .

Financial Results

Consolidated results (GAAP and non-GAAP)

Metric	Q1 2025	Q2 2025	Q3 2025
Operating Revenues (GAAP)	$1.904B	$1.965B	$1.817B
GAAP Diluted EPS	$0.68	$0.67	$0.42
Adjusted EPS (non-GAAP)	$0.80	$0.48	$0.41
Adjusted EBITDAX	$1.337B	$1.105B	$1.084B
Discretionary Cash Flow	$1.135B	$0.949B	$1.148B
Free Cash Flow	$0.663B	$0.329B	$0.533B
Unit Operating Cost ($/boe)	$9.97	$9.34	$9.81

Notes: Adjusted metrics per company definitions with reconciliations in the release tables .

Production and price KPIs

KPI	Q1 2025	Q2 2025	Q3 2025
Total Equivalent Production (MBoepd)	746.8	783.9	785.0
Oil (MBopd)	141.2	155.4	166.8
Natural Gas (MMcf/d)	3,043.8	2,998.6	2,894.6
NGLs (MBopd)	98.3	128.7	135.8
Realized Oil Price ($/Bbl, ex-hedges)	$69.73	$62.80	$64.10
Realized Gas Price ($/Mcf, ex-hedges)	$3.28	$2.20	$1.95
Capex (cash, GAAP)	$472M	$620M	$615M
Capex (incurred, non-GAAP)	$552M	$569M	$658M
Net Wells Turned In-Line (net)	37.3	61.5	48.0

Segment production (daily)

Region	Q2 2025 Daily Eq (MBoepd)	Q3 2025 Daily Eq (MBoepd)
Marcellus Shale	343.5	329.6
Permian Basin	358.6	367.3
Anadarko Basin	81.3	87.7
Total Company	783.9	785.0

Additional Q3 detail: Permian oil 160.1 MBopd; Marcellus gas 1,977.6 MMcf/d; Anadarko oil 6.5 MBopd/NGL 31.9 MBopd .

Versus S&P Global Consensus (EPS, revenue, EBITDA)*

Metric	Q1 2025	Q2 2025	Q3 2025
EPS (Primary EPS) – Estimate	$0.796*	$0.449*	$0.431*
EPS (Primary EPS) – Actual	$0.80	$0.48	$0.41
Revenue – Estimate	$2.029B*	$1.686B*	$1.754B*
Revenue – Actual (S&P standardized)	$1.937B*	$1.665B*	$1.676B*
EBITDA – Estimate	$1.383B*	$1.063B*	$1.090B*
EBITDA – Actual (standardized)	$1.221B*	$1.283B*	$1.089B*

Notes: EPS “Actual” uses company Adjusted EPS where applicable for comparability with consensus; S&P revenue/EBITDA reflect standardized definitions and can differ from reported “operating revenues”/Adjusted EBITDAX. Values retrieved from S&P Global.*

Guidance Changes

Metric	Period	Previous Guidance	Current Guidance	Change
Total Equivalent Production (MBoed)	FY 2025	755–780 (mid 768)	772–782 (mid 777)	Raised
Gas (MMcf/d)	FY 2025	2,875–2,950 (mid 2,913)	2,925–2,965 (mid 2,945)	Raised
Oil (MBopd)	FY 2025	157–163 (mid 160)	159–161 (mid 160)	Tightened
Capex (non-GAAP)	FY 2025	$2.1–$2.3B	≈$2.31B (midpoint)	Maintained (midpoint refined)
Total Equivalent Production (MBoed)	Q4 2025	—	770–810	New
Oil (MBopd)	Q4 2025	—	172–178	New
Gas (MMcf/d)	Q4 2025	—	2,775–2,925	New
Capex (non-GAAP)	Q4 2025	—	≈$530M	New
Effective Tax Rate	FY 2025	22% (40–60% current tax)	22% and no Q4 cash taxes	Clarified

Earnings Call Themes & Trends

Topic	Previous Mentions (Q1–Q2 2025)	Current Period (Q3 2025)	Trend
Capital efficiency, cost per foot	Q1/Q2: Efficiency gains across basins; Permian $/ft down 12% YoY; Anadarko 3-mile projects; Marcellus 17k’ laterals	Further cost-downs on acquired Permian assets (~10%); LOE savings target ~15%; microgrids to cut power costs up to 50%	Improving
Harkey/Windom issues	Q2: Localized issue; remediation and design changes; new adjacent wells meeting/exceeding expectations	Harkey remediation largely behind; Q3 LOE elevated from workovers; expect moderation in Q4	Stabilizing
Gas marketing diversification	Q2: CPV Basin Ranch power deal (50 MMcf/d from 2028); LNG/power portfolio ~30% of gas volumes	Continuing to pursue long-haul egress and power netbacks to mitigate Waha basis	Expanding
FY25/2026 outlook	Q2: Consistent activity; 2026 capex efficient	“Soft” 2026 guide: capex modestly down; 0–5% BOE growth, ~5% oil growth targeted	Balanced discipline
Shareholder returns/deleveraging	Q1–Q2: Prioritized term loan paydown; buybacks back-half weighted	Repaid $250M in Q3 (total $600M YTD); resumed buybacks in Oct; maintain $0.22 dividend	More balanced (debt + buybacks)
Activism/governance narrative	—	Kimmeridge letter urges Permian focus and governance changes; mgmt highlights multi-basin benefits	Emerging risk factor

Management Commentary

Strategy and positioning: “We remain committed to a long-term path of consistency, profitable growth, and value creation… Our low breakevens and deep inventory… provide the opportunity to deliver through the cycles” .
Portfolio advantages: “We think we’re seeing benefits of… a multi-basin, multi-commodity company” . “Highest PVIs in our portfolio are coming from our Marcellus project” .
Capital outlook: “A current snapshot suggests that capital should be down modestly [in 2026]… while still maintaining production parameters” .
Marketing: “We are prepared to be patient and not front-run demand increases… approximately 30% of Coterra’s gas production [is] in diversified arrangements” .
Balance sheet and returns: “We reinitiated our share buyback program… [and] are making meaningful progress… getting our leverage back to around 0.5x net debt to EBITDA” .

Q&A Highlights

Costs and LOE: Q3 LOE uptick tied to workovers; mgmt expects Q4 moderation and year to finish near midpoints .
Buybacks vs deleveraging: With term loans largely reduced, management is “feathering in” buybacks while continuing deleveraging; aims to return to robust payout levels similar to prior years .
2026 capex: “Soft” guide suggests modestly down capex while maintaining growth; flexibility retained to adjust to commodity conditions .
Waha and takeaway: Waha weakness acknowledged; pursuing long-haul pipe options and in-basin power deals to improve realizations and flow assurance .
Activism: Management acknowledged the Kimmeridge letter, reiterating benefits of the multi-basin model without engaging on specifics .

Estimates Context

Q3 2025 vs S&P Global consensus: EPS $0.41 vs $0.43 (miss); standardized revenue ≈$1.68B vs $1.75B (miss); standardized EBITDA ≈$1.09B vs $1.09B (in line). On a reported basis, GAAP operating revenues were $1.817B and Adjusted EBITDAX $1.084B (definitions differ from S&P standardized metrics) . Values retrieved from S&P Global.*
Trajectory: Q2 EPS beat ($0.48 vs $0.45) and Q1 in line ($0.80 vs $0.80), while revenue was modestly below in Q1–Q2 on standardized basis.*
Where models may adjust: higher Q4 oil mix (172–178 MBopd guide) and raised FY gas volumes could prompt upward tweaks to Q4/FY volume and cash flow forecasts; LOE normalization in Q4 would support margins .

Key Takeaways for Investors

Production momentum continues into Q4 with an oil-weighted ramp (172–178 MBopd), while FY25 volume guidance increased; expect a supportive mix shift near term .
Despite Q3 unit cost uptick, management expects normalization in Q4; cost synergies in the Permian plus microgrid power savings represent tangible 2026 margin levers .
Gas price/basis headwinds (Waha) are being mitigated by portfolio diversification (LNG, power, long-haul pipes), suggesting resiliency through gas cycles .
Balance sheet strengthening remains a priority (term loans down $600M YTD) with opportunistic buybacks resumed — a constructive setup for higher capital returns in 2026 .
The 2026 “soft” guide balances capital discipline (modestly down capex) with 0–5% BOE and ~5% oil growth, reinforcing a durable FCF profile across cycles .
Activist scrutiny introduces potential strategic/governance actions; monitoring Board responses could be an incremental catalyst or overhang .
Near-term trading lens: modest headline miss vs consensus (EPS/revenue) may be offset by raised FY volumes, Q4 oil inflection, and clear cost/return progress — positioning shares for narrative improvement as execution continues .

Appendix: Additional Disclosures and Data Points

Dividend: $0.22/share payable Nov 26, 2025; annualized yield reference 3.8% at $23.40 (as of Oct 30, 2025 close) .
Capital structure and liquidity: Total debt $3.9B, cash $98M, undrawn $2.0B revolver; total liquidity ≈$2.1B; net debt/Adj Pro Forma EBITDAX 0.8x (TTM) .
Q4 2025 guide specifics: Total production 770–810 MBoepd; oil 172–178 MBopd; gas 2.775–2.925 Bcf/d; capex ≈$530M .

Footnote: *Values retrieved from S&P Global.