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CE

Coterra Energy Inc. (CTRA)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 delivered strong execution: total production 682 MBoepd and both oil (113 MBopd) and gas (2,779 MMcf/d) finished above the high end of guidance, while cash capex landed near the low end; GAAP EPS was $0.40 and adjusted EPS $0.49 as operating revenues were $1.40B pre-hedge and $1.395B GAAP .
  • 2025 outlook reaffirmed at the midpoint: total BOE up ~9% YoY, oil up ~47%, gas roughly flat; company raised the base dividend 5% to $0.22/sh and plans to return ≥50% of 2025 FCF while prioritizing repayment of $1.0B term loans, targeting ~0.5x net debt/EBITDA “home” leverage .
  • Permian integration tracking ahead: run-rate synergies of ~$50mm expected; 2025 Permian dollar-per-foot planned cost $960 (down 6% YoY), with Culberson “row” program (57 wells) completed ahead of schedule at $864/ft and early production exceeding expectations .
  • Gas optionality returning: management restarted Marcellus activity with two rigs beginning in April and could add ~$50mm capex in H2 if fundamentals hold; they highlighted emerging power-demand/data-center opportunities for Waha gas and LNG-linked sales diversification as medium-term catalysts .

What Went Well and What Went Wrong

  • What Went Well
    • Production and capital execution beat: “oil and natural gas production each came in over 3% above the high end of guidance” with incurred capex near the low end; FCF was $351mm in Q4 .
    • Permian efficiency step-up: 2025 cost plan of $960/ft (-6% YoY); Culberson Wyndham Row completed ahead of schedule at $864/ft with first 3 months’ cumulative output exceeding expectations; simul-frac and automation are raising pumping hours and cutting transition times .
    • Shareholder returns and balance sheet: 89% of 2024 FCF returned ($1.086B) and base dividend increased 5%; plan to return ≥50% of 2025 FCF while deleveraging $1B term loans .
  • What Went Wrong
    • YoY revenue and EPS pressure: operating revenue fell to $1.395B vs $1.596B in Q4’23 and GAAP EPS fell to $0.40 vs $0.55, reflecting lower commodity prices and derivative losses .
    • Unit OpEx mix headwind: management guided higher per-unit costs with more oily, low-GOR Permian barrels (higher LOE per BOE), albeit with strong margins; Q4 unit operating cost was $8.89/BOE vs $8.41 in Q4’23 .
    • Gas price backdrop still a governor: 2024 proved reserves declined ~2% YoY primarily on lower gas prices and fewer PUD bookings; gas realizations remained low ($2.02/Mcf in Q4) despite execution .

Financial Results

MetricQ4 2023Q2 2024Q3 2024Q4 2024
Operating Revenues ($mm)$1,596 $1,271 $1,359 $1,395
Net Income ($mm)$416 $220 $252 $297
GAAP EPS (Basic)$0.55 $0.30 $0.34 $0.40
Adjusted EPS (non‑GAAP)$0.52 $0.37 $0.32 $0.49
Discretionary Cash Flow ($mm)$881 $725 $670 $776
Free Cash Flow ($mm)$413 $246 $277 $351
Cash Capex ($mm)$468 $479 $393 $425
Unit Operating Cost ($/BOE)$8.41 $8.35 $8.73 $8.89
Total Production (MBoepd)697.4 669.2 669.1 681.5
Oil (MBopd)104.7 107.2 112.3 113.0
Natural Gas (MMcf/d)2,970.0 2,779.8 2,682.0 2,778.9

Non-GAAP note: Adjusted EPS and cash flow measures are as defined by the company; reconciliations provided in exhibits .

Segment production and realized prices (Q4 2024)

RegionOil (MBopd)Gas (MMcf/d)NGL (MBopd)Realized Gas ($/Mcf)Realized Oil ($/Bbl)
Marcellus Shale–2,042.8 –$2.27 –
Permian Basin103.8 517.5 78.3 $0.79 $68.55
Anadarko Basin9.1 217.2 27.1 $2.51 $68.80

Q4 2024 KPIs

KPIQ4 2024
Discretionary Cash Flow ($mm)$776
Free Cash Flow ($mm)$351
Cash from Operating Activities ($mm)$626
Capital Expenditures – cash ($mm)$425
Wells TIL – Net (count)34.7

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Total Equivalent Production (MBoepd)FY 2025710–770 (Nov preview) 710–770 Maintained at midpoint
Oil (MBopd)FY 2025152–168 (Nov preview) 152–168 Maintained at midpoint
Gas (MMcf/d)FY 20252,675–2,875 (Nov preview) 2,675–2,875 Maintained at midpoint
Total Capex ($bn)FY 2025$2.1–$2.4 (Nov preview) $2.1–$2.4 Maintained; mix updated
Permian D&C CapexFY 2025Prior Nov level ~$70mm lower vs Nov (services, synergies) Lowered
Marcellus D&C CapexFY 2025Prior Nov level ~$50mm higher vs Nov (restart in Q2) Raised
Base DividendQ4 2024$0.21/sh prior $0.22/sh (+5% YoY) Raised
Shareholder ReturnsFY 2025≥50% of FCF (framework) ≥50% of FCF; prioritize deleveraging Maintained
Term Loan RepaymentFY 2025n/aRepay $1.0B term loans in 2025 New deleveraging detail
Q1 2025 ProductionQ1 2025n/a710–750 MBoepd; oil 134–144 MBopd; gas 2,850–3,000 MMcf/d New quarterly guide
Q1 2025 CapexQ1 2025n/a$525–$625mm New quarterly guide

Earnings Call Themes & Trends

TopicQ2 2024 (Q-2)Q3 2024 (Q-1)Q4 2024 (Current)Trend
Gas market/curtailmentsCurtailments and potential delays in Marcellus; economics require mid-$3 Henry Hub, upper Marcellus higher; flexibility stressed Continued curtailments; month-to-month; LNG deals signed (200 MMcf/d from ’27/’28) Restarting Marcellus with 2 rigs in April; could add ~$50mm capex H2 if fundamentals hold Improving optionality
Permian efficiencies/simul‑fracCost/ft −11% YoY; simul‑frac “weapon” in Culberson Culberson row savings at high end; simul‑frac adds ~$25/ft savings vs zipper 2025 Permian $960/ft (−6% YoY); Culberson row completed $864/ft; ML‑driven frac designs Sustained efficiency gains
LNG and power demandMacro bullishness but oversupply near-term Three LNG agreements for intl index netbacks; Matterhorn, Waha dynamics Exploring power gen/data-center partnerships (Waha advantaged); bolstering power-linked pricing Expanding commercialization
Capital allocation/returns120% of FCF returned in Q2; opportunistic buybacks 96% of FCF returned in Q3; ≥50% FCF framework reiterated ≥50% 2025 FCF returns; base dividend +5%; $1B debt paydown priority Balanced with deleveraging
M&A postureDisciplined; value and entry cost emphasis Active but selective; optionality with simul‑frac/capital Franklin Mountain/Avant closed; $50mm run-rate synergies; opportunistic future M&A Integration/efficiency focus
Unit costs/mixUnit cost mid-guidance; gas-weight helps per-BOE cost Unit cost $8.73/BOE Unit cost $8.89/BOE; OpEx guide higher on oilier mix Mix-driven upward bias

Management Commentary

  • Strategy and flexibility: “Flexibility is the coin of the realm.” Management emphasized capital allocation agility across basins and commodities to maximize returns and per-share value .
  • Q4/2024 performance: “Oil and natural gas production each came in over 3% above the high end of guidance... pre-hedge revenue over $1.4 billion... adjusted net income of $358 million or $0.49 per share” .
  • 2025 posture: “We expect to repay our $1 billion of term loans... get leverage back to ~0.5x net debt to EBITDA... return 50% or more of annual free cash flow” .
  • Permian integration: “Run rate synergies on these new assets of roughly $50 million... savings not from reduced activity, but cost savings vs prior operators” .
  • Operational excellence: “Grid-powered electric simul-frac... records in pumping hours... Wyndham Row completed ahead of schedule at $864/ft” .

Q&A Highlights

  • Marcellus restart thresholds and timing: Returns competitive at current outlook; two rigs restart in April with flexibility to modestly accelerate; potential ~$50mm incremental 2025 capex if fundamentals hold .
  • Power/data-center demand: Active discussions in Permian (also Anadarko/Marcellus inbound); pursuing combined-cycle and behind‑the‑meter solutions for data centers; commercial structures still evolving .
  • Capex/Permian synergies and cost: Permian $/ft down ~10% vs prior programs on new assets; consolidation onto one frac line; directional, pad, and frac design optimization .
  • OpEx mix: Higher unit OpEx guided due to low‑GOR oil growth on acquired Permian assets—“higher per unit cost on LOE, but fantastic margins” .
  • Capital returns vs deleveraging: Buyback not “on hold” but back‑end loaded as debt reduction prioritized early in 2025; opportunistic approach maintained .

Estimates Context

  • Comparison to Wall Street consensus: S&P Global consensus estimates for Q4 2024 EPS and revenue were unavailable due to access limits at query time; we will update comparisons when available. In lieu of consensus, results were benchmarked against company guidance (production beat; capex near low end) and prior-year/quarter performance . Values retrieved from S&P Global.*

Key Takeaways for Investors

  • Operational momentum plus portfolio flexibility: Multi-basin optionality and Permian cost/efficiency gains should sustain above-peer execution into 2025, with oil growth (~47% YoY midpoint) a key driver .
  • Deleveraging as a near-term catalyst: Planned $1B term loan repayment and ≥50% FCF returns in 2025 could support multiple expansion if commodity tape cooperates .
  • Gas upside optionality: Marcellus restart and potential H2 acceleration, LNG-linked netbacks, and emerging power/data-center demand provide cyclical and structural torque to gas realizations .
  • Cost discipline is compounding: 2025 Permian dollar-per-foot plan ($960) and Culberson row execution at $864/ft reinforce durable capital efficiency gains and margin resilience .
  • Mix effects on unit costs: Expect higher per-BOE operating cost with a more oil-weighted mix; offset by stronger margins and cash flow per BOE .
  • Non‑GAAP adjustments matter: Adjusted EPS of $0.49 vs GAAP $0.40 in Q4 reflects derivative marks; investors should focus on cash metrics (DCF $776mm, FCF $351mm) and capex discipline .
  • Watch list: integration synergy capture, Marcellus cadence (rigs and TILs), power/LNG commercialization milestones, and execution vs Q1 2025 guide (710–750 MBoepd; capex $525–$625mm) .

Appendix: Additional Detail

Fourth-Quarter 2024 operational highlights (company reported)

  • Production: 682 MBoepd; Oil 113.0 MBopd; Gas 2,779 MMcf/d; all above high-end of guidance .
  • Pricing: Oil $68.57/Bbl; Gas $2.02/Mcf; NGL $20.94/BOE (ex-hedge) .
  • Cash metrics: CFO $626mm; DCF $776mm; FCF $351mm; Capex (cash) $425mm .

Three-year outlook framing

  • 2025–27: ≥5% annual oil growth; 0–5% BOE growth; $2.1–$2.4B annual capex; average reinvestment rate below 50% at recent strip; flexibility across basins maintained .