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EOG RESOURCES INC (EOG)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 2024 revenue was $5.585B and diluted EPS was $2.23; adjusted EPS was $2.74. Sequentially softer vs Q3 on lower wellhead prices, negative hedge marks, and higher impairments; volume growth and lower per‑unit operating costs partly offset .
  • Production hit new highs: 1,095.7 MBoed, with natural gas volumes beating Q4 guidance, while NGLs came in below guidance; capex tracked in line .
  • 2025 plan: capex flat at $6.2B, ~3% oil growth and ~6% total production growth; cash breakeven in low‑$50s WTI; ROCE ≥20% at $70/$4.25; natural gas marketing uplift begins as new agreements/LNG ramps; cash taxes step up ~15% YoY due to exhausted AMT credits .
  • Capital returns remain aggressive: FY24 returned 98% of free cash flow; dividend increased 7% to $3.90 indicated annual rate; buyback authorization capacity remains large ($5.8B remaining entering 2025) .

What Went Well and What Went Wrong

  • What Went Well

    • “Fourth quarter oil and gas production volumes beat targets as did cash operating costs and DD&A” .
    • Strategic marketing: Verde pipeline in service (1.0–1.5 Bcf/d capacity) and Janus processing plant connects to Matterhorn; new agreements (Transco TLEP, Vitol) diversify pricing and minimize Waha exposure to 5–7% in 2025 .
    • Efficiency/technology: Longer laterals and in‑house motor program improved capital efficiency (drill feet/day +10%, completed feet/day +20% in Delaware in 2024) with 2025 lateral lengths up ≥20% .

  • What Went Wrong

    • Price/hedge impact: Lower composite wellhead revenue per Boe drove −$0.22 EPS QoQ; mark‑to‑market derivative losses contributed −$0.20 EPS; “Other” items −$0.38 EPS .
    • NGL volumes below Q4 guidance midpoint (actual 252.5 MBbld vs 260 MBbld midpoint) despite strong overall volumes .
    • Free cash flow outlook: 2025 guide (~$70/$4.25 scenario) discussed as softer vs some expectations due to higher cash taxes (AMT credits exhausted) and initial GP&T cost step‑ups on new transport contracts .

Financial Results

MetricQ4 2023Q2 2024Q3 2024Q4 2024
Revenue ($USD Billions)$6.357 $6.025 $5.965 $5.585
Diluted EPS (GAAP)$3.42 $2.95 $2.95 $2.23
Adjusted EPS (Non-GAAP)$3.07 $3.16 $2.89 $2.74
Composite Margin per Boe (GAAP, incl exploration)$23.07 $21.70 $19.98 $15.88
KPIQ4 2023Q2 2024Q3 2024Q4 2024
Total Production (MBoed)1,026.2 1,047.5 1,075.7 1,095.7
Crude Oil & Condensate (MBbld, Total)485.2 490.7 493.0 494.6
NGLs (MBbld)235.8 244.8 254.3 252.5
Natural Gas (MMcfd, Total)1,831 1,872 1,970 2,092
Avg Wellhead Revenue per Boe ($)$48.27 $47.31 $44.31 $42.74
Free Cash Flow ($USD Billions, Non-GAAP)$1.477 $1.374 $1.491 $1.277
Capital Expenditures ($USD Billions, Non-GAAP)$1.512 $1.668 $1.497 $1.358

Explanations of EPS bridge (Q4 vs Q3):

  • Realized prices: Composite wellhead −$1.57/Boe drove −$0.22 EPS .
  • Volumes and margin mix: +$0.04 EPS contribution .
  • Operating costs per Boe reduction: +$0.04 EPS .
  • Hedge marks: After‑tax shift contributed −$0.20 EPS .
  • Other items: −$0.38 EPS (includes GPM revenue, asset sales, exploration, impairments, TOTI, interest, tax rate effects) .

Guidance Changes

MetricPeriodPrevious Guidance (Midpoint)Current/ActualChange
Crude Oil & Condensate (MBbld, Total)Q4 2024493.0 494.6 Beat (slight)
NGLs (MBbld)Q4 2024260.0 252.5 Miss (below)
Natural Gas (MMcfd, Total)Q4 20242,075 2,092 Beat
Total MBoedQ4 20241,098.9 1,095.7 In‑line (slight below)
Capital Expenditures ($B, Non-GAAP)Q4 2024$1.33 $1.358 In‑line
Regular Dividend (Indicated Annual)FY 2024/25$3.90 (raised in Q3) $3.90 maintained Maintained
Capex PlanFY 2025NA$6.2B; flat YoY New (flat)
Volume GrowthFY 2025NA~3% oil, ~6% total New (growth)
Cash BreakevenFY 2025NALow‑$50s WTI New
ROCE at $70/$4.25FY 2025NA≥20% New
Cash TaxesFY 2025NA~15% YoY increase (AMT credits exhausted) New (higher)
GP&T CostsFY 2025NAInitial step‑up on new transport contracts New (higher near‑term)

Earnings Call Themes & Trends

TopicPrevious Mentions (Q2 2024)Previous Mentions (Q3 2024)Current Period (Q4 2024)Trend
Operational technology (longer laterals, in‑house motors)Not detailed in docs scannedImproved pump rates; lateral records; motor program savings Efficiency gains sustained; 2025 lateral lengths up ≥20% Strengthening
Marketing & LNG exposureNot detailed in docs scannedPrice realizations strong; diversified market access Verde in service; Janus to Matterhorn; Cheniere Corpus Christi Stage 3 (300k MMBtu/d) ramp in 2025; TLEP/Vitol deals Increasing uplift
Macro oil/gasNot detailed in docs scannedU.S. liquids growth moderating; gas demand rising with LNG/power Oil range‑bound $65–$85 WTI; gas inventories fell below 5‑yr avg; LNG start‑ups supportive Steady constructive
International (Trinidad, Bahrain)Not detailed in docs scannedNATrinidad Mento/Coconut; Bahrain JV operator; drilling 2H25 New/expanding
Sustainability (methane/CCS)NA2023 report, methane monitoring, CCS pilot Continues as operating standard; looking to deploy more broadly Ongoing
Balance sheet optimization & cash returnsNATarget $5–$6B debt over 12–18 months; return >70% FCF Buybacks opportunistic; >70% FCF target; large authorization available Continuing

Management Commentary

  • “2024 was an outstanding year... proved reserves increased by 6% to 4.7 billion Boe... returned a record $5.3 billion to shareholders... 98% of 2024 free cash flow” — Ann Janssen, CFO .
  • “Our plan... grounded in capital discipline, operational excellence, sustainability, and our culture... portfolio earns among the highest returns... >55% ATROR using $45 oil and $2.50 gas bottom‑cycle pricing” — Ezra Yacob, CEO .
  • “We lowered average well cost by 6%... extended laterals and in‑house drilling motor program... maintained GHG and methane intensity below 2025 targets” — Jeff Leitzell, COO .
  • “2025 capex flat at $6.2B... cash breakeven in low 50s... at $70/$4.25 we expect ROCE of 20% or greater” — Ann Janssen, CFO .

Q&A Highlights

  • Free cash flow guide and 2025 drivers: Management cited higher cash taxes (AMT credits exhausted) and initial GP&T step‑ups; emerging plays and infrastructure spend tilt benefits more to 2026 .
  • International spend: ~+$100MM YoY to advance Trinidad (Mento, Coconut) and Bahrain JV; volume impact mostly in 2026 .
  • Natural gas differentials: Gulf Coast basis widened early 2025; realizations expected to inflect as new agreements ramp during the year (Henry Hub link, Southeast markets) .
  • Buybacks and balance sheet: Target $5–$6B gross debt over 12–18 months; maintain $5–$6B cash; opportunistic buybacks above 70% FCF return .
  • Dorado cadence: Maintain 1‑rig program; focus on long‑term cost reduction and scale, not near‑term price volatility .

Estimates Context

  • Wall Street consensus (S&P Global) for Q4 2024 EPS/Revenue/EBITDA was unavailable due to data access limits at time of request; therefore, estimate comparisons cannot be provided. Values retrieved from S&P Global were not available at time of analysis.*

Key Takeaways for Investors

  • Q4 print: lower prices and hedge losses compressed margins; volumes and efficiency initiatives cushioned EPS. Near‑term narrative hinges on LNG ramp and marketing agreements improving gas realizations through 2025 .
  • 2025 setup: Capex flat, modest oil/total growth, breakeven low‑$50s WTI, and ROCE ≥20% at $70/$4.25 underscore resilient returns despite higher cash taxes and GP&T ramp .
  • Capital returns: With large buyback capacity and dividend maintained at a higher level, expect continued high FCF payout; balance sheet optimization increases flexibility for counter‑cyclical bolt‑ons and buybacks .
  • Operational edge: Longer laterals and in‑house motor program support ongoing cost declines; Utica activity up ~50% in 2025 with costs <$650/ft and F&D $6–$8/boe, enhancing multi‑basin durability .
  • Gas leverage: Verde/Janus and Henry Hub‑linked contracts minimize Waha exposure (5–7%) and position Dorado to benefit from LNG/power demand growth; watch differentials and contract ramp timing as catalysts .
  • International option value: Trinidad developments and Bahrain JV add longer‑dated, potentially competitive returns; minimal 2025 volume impact but increasing strategic depth .
  • Trading lens: Near term, stock likely reacts to margin trajectory (gas realizations/differentials, DD&A/cash costs) and to clarity on buyback pace; medium term, execution on Utica scale‑up and gas marketing uplift are key re‑rating drivers .