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AC

APA Corp (APA)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 2024 revenue was $2.71B, GAAP EPS $0.96 and adjusted EPS $0.79; adjusted EBITDAX was $1.55B and free cash flow (FCF) was $420M, helped by stronger production (reported 488 Mboe/d; adjusted 418 Mboe/d) and gas marketing gains .
  • Management introduced a multi‑year cost‑reduction program targeting at least $350M run‑rate savings by year‑end 2027, a 2025 upstream capex plan of $2.5–$2.6B, U.S. oil at 125–127 kbopd, and total adjusted production of ~396 Mboe/d; committed to return at least 60% of FCF to shareholders .
  • Key 2025 call color: expected ~$600M net gain from gas trading/LNG (≈$400M Permian trading, ≈$200M Cheniere), Permian operated LOE/boe ~20% lower vs 2024, and front‑half weighted capex (Suriname/Alaska long‑lead) .
  • Strategic catalysts: Suriname Block 58 FID executed (first oil 2028), Egypt gas price framework supports rig shift and higher realized gas prices, and portfolio streamlining (Callon integration, Central Basin Platform sale; ~$774M Q4 proceeds) .

What Went Well and What Went Wrong

  • What Went Well

    • Delivered $420M of Q4 FCF (highest 2024 quarter) and $841M FY FCF; returned 71% of FY FCF to shareholders (dividends + buybacks) .
    • Production above guidance in all regions with lower-than-guided capital due to Permian well‑cost reductions; Callon Delaware breakevens reduced to $61/bbl vs $78 (2023 base) .
    • Cost program launched to deliver ≥$350M sustainable annual savings by YE2027; Permian operated LOE/boe expected ~20% lower in 2025 vs 2024 .
    • Quote: “We are confident that our disciplined approach to capital allocation and rigorous cost management will underpin strong free cash flow growth… further bolstered by the GranMorgu [Suriname] project… with first oil in 2028” – CEO John Christmann .

  • What Went Wrong

    • Q4 DD&A and LOE were higher than guidance: accelerated Alpine High depreciation (reserve write‑down with negative Waha) and an extra North Sea cargo lifting increased expenses .
    • $190M increase in contingent liability for previously sold Gulf of Mexico properties (Fieldwood) impacted results; GAAP also influenced by a $224M U.S. deferred tax benefit write‑off of UK investment .
    • Egypt gross volumes continue modest decline; receivables remain a watch‑item (management expects progress in 2025) .

Financial Results

MetricQ2 2024Q3 2024Q4 2024
Total Revenues ($USD Millions)2,543 2,531 2,712
GAAP Diluted EPS ($)1.46 -0.60 0.96
Adjusted Diluted EPS ($)1.17 1.00 0.79
Adjusted EBITDAX ($USD Millions)1,576 1,557 1,550
Net Cash from Operating Activities ($USD Millions)877 1,339 1,036
Free Cash Flow ($USD Millions)103 219 420
Reported Production (Mboe/d)473.4 467.5 488.3
Adjusted Production (Mboe/d)405.5 394.6 418.3

Segment production (adjusted) – BOE/d

Geography (Adjusted)Q2 2024Q3 2024Q4 2024
United States303,416 300,709 313,227
Egypt65,296 68,825 69,986
North Sea36,778 25,029 35,134
Total Adjusted405,490 394,563 418,347

KPIs and cost/price context

KPIQ2 2024Q3 2024Q4 2024
U.S. Oil (kbopd, adjusted)139.4 143.3 147.6
Avg Oil Price ($/bbl, total)82.28 78.06 72.42
Avg Gas Price ($/mcf, total)1.77 1.43 2.20
Avg NGL Price ($/bbl, total)21.68 21.29 25.08
Lease Operating Expense ($MM)460 418 474
Total Upstream Capital Investment ($MM)839 698 592
Net Debt ($MM, period end)6,583 6,308 5,419

Additional Q4 context

  • Realized prices pre‑release guide (Jan 22): U.S. oil ~$70.25/bbl, U.S. gas ~$1.00/mcf, International oil ~$74.75/bbl; curtailments ~23.5 Mboe/d in Q4 (in line with November guidance) .
  • Asset sale (Central Basin Platform) closed Dec 31 with net proceeds of ~$774M, boosting Q4 investing cash flow .

Guidance Changes

MetricPeriodPrevious Guidance (Q3’24)Current Guidance (Q4’24)Change
Upstream CapitalFY2025$2.5–$2.6B $2.5–$2.6B (front‑half weighted) Maintained; cadence specified
Permian RigsFY20258 rigs 8 rigs Maintained
Egypt RigsFY202512 rigs incl. 1 gas 12 rigs; likely 2–3 gas rigs as program ramps Tilting more to gas
Adjusted ProductionFY2025Mid‑single‑digit adjusted BOE growth ~396 Mboe/d (flat to modest growth vs 2024) Refined/quantified
U.S. OilFY2025Directional ~130 kbopd “hold flat” (implied) 125–127 kbopd Refined, slightly lower
Cost SavingsThrough 2027N/A≥$350M run‑rate by YE2027; $100–125M run‑rate by YE2025, ~$60M in‑year 2025 New
Permian Operated LOE/boeFY202510–15% YoY reduction basket (Q3 directional) ~20% lower vs 2024 (Permian LOE/boe) More ambitious
Gas Trading + LNGFY2024~$500M total (raised in Q3) ~$600M in FY2025; ≈$400M pipeline trading, ≈$200M Cheniere New year outlook
Egypt Realized Gas PriceFY2025Framework signed (no numbers) Q1 ≥$3.15/mcf; FY $3.40–$3.50/mcf; upside with program New specifics
Capital ReturnsOngoing≥60% of FCF ≥60% of FCF; active buybacks at depressed levels Maintained

Earnings Call Themes & Trends

TopicPrevious Mentions (Q2’24, Q3’24)Current Period (Q4’24)Trend
Cost reductionsRaised synergy run‑rate to $250M (Callon); targeted 10–15% y/y reduction across LOE/G&A/GPT/interest in 2025 Multi‑year ≥$350M savings by YE2027; $100–125M run‑rate by YE2025; org simplification underway Expanding
Permian integration$1M/well cost reduction; spacing/frac design optimizations starting; 9–10 rigs in 2H’24 8‑rig 2025 plan; U.S. oil 125–127 kbopd; LOE/boe ~20% lower; reduced breakeven ($61/bbl) on Callon acreage Efficiency improved, growth moderated
Egypt gasNew gas price framework signed; add 1 gas rig Shift 2–3 rigs to gas; Q1 realized ≥$3.15/mcf and FY $3.40–$3.50; infrastructure manageable; receivables progress expected Positive pivot
Suriname Block 58FPSO secured; FID before YE’24; first oil 2028 FID confirmed; 2025 focus on long‑leads/FPSO; first oil 2028 On track
North Sea/AROCessation by 12/31/2029; ARO PV net ~$1.2B; free‑cash‑flow management focus 2025 ARO spend ~$100M + $70M Fieldwood DCOM; North Sea ARO to grow later Increasing ARO cadence
Gas tradingFY’24 lift to ~$500M; wider Waha‑Gulf diffs drive upside FY’25 ~ $600M; $400M pipelines/$200M LNG; high volatility acknowledged High but volatile
AlaskaIncreased leasehold; 2025 winter drilling planned Saki exploration well progressing; ops smooth, results pending Active appraisal

Management Commentary

  • “We delivered production volumes above guidance in all three of our operating regions and did so on a capital program that came in lower than guidance… main drivers in delivering $420 million of free cash flow during the quarter” – CEO John Christmann .
  • “We are targeting at least $350 million in annualized savings by the end of 2027… $100–$125 million by the end of this year; ~$60 million in‑year capture in 2025” – CFO Steve Riney .
  • “U.S. oil volumes should be in the 125,000 to 127,000 barrels per day range [in 2025]… average realized gas price [Egypt]… full‑year $3.40 to $3.50” – CFO Steve Riney .
  • “We are confident that our disciplined approach to capital allocation and rigorous cost management will underpin strong free cash flow growth… further bolstered by the GranMorgu project in Suriname, with first oil in 2028” – CEO John Christmann .

Q&A Highlights

  • Credibility and capital allocation: Analysts challenged buybacks vs. debt reduction; management plans to balance both, citing shareholder support for buybacks and deleveraging path (term loan paydown, maturities) .
  • Permian cadence: Exit‑rate dynamics explained (11→8 rigs in 2H’24); 2025 average U.S. oil 125–127 kbopd with stable 8‑rig program; weather impacted Q1 seasonality .
  • Egypt gas program: Initial wells strong; plan to shift 2–3 rigs to gas; infrastructure largely in place; realized prices rising under new framework .
  • Marketing/LNG: 2025 net gain guide ~$600M split ≈$400M pipelines/≈$200M LNG (strip‑dependent) .
  • ARO and decommissioning: 2025 ARO ~$100M (≈$40M legacy GoM, ≈$30M North Sea, ≈$30M onshore U.S.), plus ~$70M Fieldwood DCOM; North Sea ARO increases over time .
  • Suriname milestones: 2025 focus on long leads and FPSO; project execution tracking well with operator .
  • Alaska: Saki well operations smooth; results pending .

Estimates Context

  • S&P Global (Capital IQ) Wall Street consensus for revenue/EPS was not available at the time of analysis due to access limits; as a result, explicit “vs. consensus” beat/miss is not shown. Values from S&P Global could not be retrieved at this time.

Key Takeaways for Investors

  • Near‑term FCF support remains solid: Q4 FCF of $420M and a 2025 ~$600M gas trading/LNG contribution provide cushioning despite a lower U.S. oil guide; watch Waha‑Gulf spreads and LNG prices .
  • Structural cost reset is the core 2025–2027 driver: ≥$350M run‑rate savings by 2027 (with ~20% Permian LOE/boe reduction in 2025) underpins FCF per share growth even on flat production .
  • Permian: focus on efficiency over growth (8‑rig plan, lower breakevens on Callon acreage to ~$61/bbl) should improve capital productivity and returns .
  • Egypt: gas pivot is progressing; higher realized prices and 2–3 gas rigs can stabilize/improve adjusted volumes; receivables trajectory and infrastructure de‑bottlenecking are the watch‑items .
  • Suriname: FID executed; execution risk shifts to project delivery (long‑lead/FPSO) with material multi‑year FCF uplift starting 2028 .
  • Balance sheet: Net debt fell to ~$5.4B at YE2024; management intends to continue deleveraging alongside buybacks within the ≥60% FCF return framework .
  • Trading setup: Shares may be sensitive to quarterly cadence (front‑loaded capex, weather), gas basis volatility, and updates on Egypt gas/receivables and Alaska Saki results .