Q4 2024 Summary
Published Feb 27, 2025, 9:19 PM UTC- Significant cost reduction initiatives: APA is targeting $350 million in annualized cost savings by the end of 2027, with an objective to achieve run-rate savings of $100 million to $125 million by the end of 2025. They have already made progress with reductions in global overhead, capturing $35 million in annual run-rate savings. These cost reductions are expected to drive free cash flow expansion over the next several years.
- Strong asset base with long-term visibility: APA has confidence in the durability and sustainability of its assets, particularly in the Permian Basin. They have visibility to maintain flat production levels through 2029 and into the next decade, with ample inventory to support operations at the current 8-rig pace. This provides a stable foundation for future growth and free cash flow generation.
- Enhancing returns through gas opportunities in Egypt: APA has signed a new gas price agreement in Egypt, making gas returns on par with oil. They are shifting rigs to gas drilling, which is expected to increase gas production for the first time in over a decade. Early results are encouraging, and the company is considering dedicating additional rigs to gas. This strategy leverages existing infrastructure and taps into high gas yield opportunities, potentially boosting revenues and margins.
- Persistent Share Price Underperformance Despite Strong Free Cash Flow Generation: Despite reporting $420 million of free cash flow in the fourth quarter , APA's share price continues to underperform relative to peers. Analysts highlight a potential "crisis of confidence" in the company's guidance, as substantial financial results are not translating into shareholder value.
- Ineffective Capital Allocation Strategy Focused on Share Buybacks: Over the past three years, APA has prioritized share repurchases, yet the share price has declined by 57% during that period. Analysts question the effectiveness of this strategy, suggesting that continued buybacks have not supported the share price and that the company should consider reducing debt instead.
- High Debt Levels and Capital Structure Concerns Leading to Higher Discount Rates: Concerns have been raised that APA's capital structure, with relatively high debt levels, contributes to a higher discount rate due to business volatility. Analysts argue that unless the company reduces debt significantly, the discount rate won't normalize, potentially limiting stock price appreciation despite expected free cash flow growth.
| Metric | YoY Change | Reason |
|---|---|---|
Total Revenue | +25% YoY (Q4 2024: $2,712M vs Q4 2023: $2,167M) | Total revenue increased by $545M driven by stronger contributions from key geographic segments—the U.S. ($981M) and Egypt ($699M)—and enhanced production volumes, including benefits from acquisitions like Callon, relative to the previous year. |
Operating Income | –48% YoY (Q4 2024: $500M vs Q4 2023: $971M) | Operating income declined significantly as higher operating expenses, margin pressure, and potential impairment charges (reflecting trends seen in prior quarters) squeezed margins compared to Q4 2023. |
Net Income | –80% YoY (Q4 2024: $354M vs Q4 2023: $1,773M) | Net income dropped sharply by over $1.4B due to substantial impairments and other non‐core expense adjustments that eroded profitability, contrasting with the stronger Q4 2023 performance. |
Earnings per Share | Decreased from $5.76 to $0.96 per share | EPS fell dramatically largely because the steep decline in net income (and corresponding impairments) reduced earnings available to shareholders, consistent with the drop in operating and net income performance. |
Oil Segment Revenue | Q4 2024 vs Q3 2024: Collapsed from $1,007M to $4M | Oil revenue collapsed almost entirely which may indicate a significant operational or reporting change—possibly from asset reclassification or a major step-down in oil production activity—compared with the strong performance in Q3 2024. |
Natural Gas Revenue | Q4 2024 vs Q3 2024: Rebounded from $7M to $234M | Natural gas revenue rebounded sharply as operational adjustments or improved market conditions dramatically boosted revenues in Q4 2024 relative to the very low levels recorded in Q3 2024. |
NGL Revenue | Q4 2024 vs Q3 2024: Reversed from $153M to –$436M | NGL revenues turned highly negative in Q4 2024 as severe volatility—likely due to sizeable write‐downs or impairments and adverse pricing/inventory revaluations—reversed the positive figures seen in Q3 2024. |
| Metric | Period | Previous Guidance | Current Guidance | Change |
|---|---|---|---|---|
Purchased Oil and Gas Sales | FY 2025 | no prior guidance | $600 million | no prior guidance |
Permian Rig Count | FY 2025 | 8 rigs in the Permian Basin | 8‑rig program in the Permian | no change |
U.S. Oil Volume (Permian) | FY 2025 | no prior guidance | 125,000 to 127,000 barrels per day | no prior guidance |
Egypt Production | FY 2025 | no prior guidance | Adjusted production expected to grow slightly year‑over‑year | no prior guidance |
Gas Prices | FY 2025 | no prior guidance | Increase from $2.96 per Mcf in Q4 2024 to at least $3.15 per Mcf in Q1 2025; full‑year average $3.40–$3.50 | no prior guidance |
Lease Operating Expense | FY 2025 | no prior guidance | About 20% lower than in 2024 | no prior guidance |
General and Administrative Costs | FY 2025 | no prior guidance | Total overhead costs expected to decrease by at least $25 million | no prior guidance |
Capital Spending | FY 2025 | $2.2–$2.3 billion for core operations plus an additional $200 million and $100 million allocated (totaling $2.5–$2.6 billion) | $2.5–$2.6 billion | no change |
Cost Reduction Initiatives | FY 2025 | no prior guidance | Targeting $350 million annualized cost savings by end of 2027 and $100–$125 million in run‑rate savings by end of FY2025 | no prior guidance |
Free Cash Flow | FY 2025 | no prior guidance | $420 million generated in Q4 2024 with ongoing focus on cost reductions and capital efficiency | no prior guidance |
Shareholder Returns | FY 2025 | no prior guidance | Maintain a 60% shareholder return program | no prior guidance |
| Topic | Previous Mentions | Current Period | Trend |
|---|---|---|---|
Cost Reduction Initiatives | Q1–Q3 discussions focused on achieving operational efficiencies and capturing cost synergies (e.g. revised synergy estimates, reductions in LOE, G&A, capital and overhead improvements) | Q4 provided detailed quantification – targeting $350 million in annualized savings by 2027; laid out phased initiatives with immediate G&A cuts and technology‑driven improvements | Recurring topic with increased detail and continued positive sentiment. |
Callon Acquisition Integration and Synergy Realization | Across Q1–Q3, integration progress was highlighted with synergy targets being raised (from $150M initially up to $250M), elimination of legacy costs, and improved operational practices on Callon assets | Q4 reaffirmed that integration is delivering improved capital and operating efficiencies – lowering breakeven costs and reinforcing the company’s forward guidance | Recurring with clear progress; sentiment has become more positive as synergies solidify. |
Permian Basin Production Stability and Rig Count Optimization | Q1–Q3 discussions outlined strategies to optimize rig counts (reducing from 11 to 8–10 rigs) while maintaining stable production levels, balancing efficiency with production targets | Q4 confirmed an 8‑rig program, targeting flat production (125,000–127,000 barrels per day) and emphasizing cost efficiency and dependable output | Recurring consistently with a stable strategy and no significant sentiment shift. |
Gas Production Strategy and Pricing Agreements in Egypt | Early discussions in Q1 offered limited details; Q2 began addressing gas opportunities and challenges, while Q3 introduced a new pricing framework to align gas economics with oil, emphasizing incremental volumes | Q4 detailed a new gas pricing agreement that equates gas returns to oil on a full‑cycle basis and outlined an aggressive, gas‑focused drilling program with promising early results | Recurring with evolving emphasis; sentiment shifts toward optimism with improved economics and clearer strategy. |
Capital Allocation, Debt Reduction, and Shareholder Returns | Q1–Q3 calls consistently reiterated the commitment to a 60% free cash flow return, balancing capital spending, debt reduction (including Callon‑related debt) and share repurchases; some caution was noted regarding capital structure | Q4 provided granular breakdowns (e.g. $2.5–$2.6B capital plan, $2.2B debt reduction plan, and detailed buyback programs) while facing analyst criticism over share price performance | Recurring theme with consistent strategy; however, Q4 introduced increased scrutiny from the market, prompting a defensive tone. |
Free Cash Flow Expansion and Financial Performance | Q1–Q3 emphasized robust free cash flow growth through cost synergies and operational efficiency, with expectations for higher second‑half performance and tie‑in to debt reduction and shareholder returns | Q4 reported record quarterly free cash flow (e.g. $420 million in Q4, $841 million full‑year), strengthened credit ratings, and clear improvements in financial performance | Recurring with increasingly positive performance metrics, reinforcing long‑term optimism. |
Exploration and Growth Opportunities in New Regions (Suriname and Alaska) | Q1 highlighted early FID studies and exploratory drilling (with mixed results such as a Bonboni dry hole in Suriname and the King Street discovery in Alaska); Q2 and Q3 advanced the narrative with FID progress and promising discoveries | Q4 emphasized a definitive FID for Suriname’s Block 58 (GranMorgu project) with first oil targeted for 2028 and noted smooth operations on the Saki well in Alaska, underscoring significant growth potential | Recurring with accelerating progress and a more optimistic outlook, signaling large future growth. |
Asset Retirement Obligations and North Sea Regulatory Risks | Q3 provided detailed ARO estimates for North Sea assets and discussed new U.K. emissions regulations that threaten long‑term production beyond 2029, prompting an early cessation and impairment charges | Q4 continued to detail ARO spending (with a breakdown for Gulf of Mexico, North Sea, and onshore U.S.) but notably did not address North Sea regulatory risks, suggesting reduced emphasis on that adverse factor | Recurring ARO discussion but with decreasing focus on regulatory risks in Q4, possibly indicating resolution or deprioritization. |
Market Sentiment and Share Price Underperformance | Not specifically mentioned in Q1–Q3 calls; the focus was primarily on operational metrics and capital deployment without market sentiment commentary | Q4 contained pointed analyst remarks about persistent share price underperformance (a 57% decline) despite strong cash flow, prompting management to defend its buyback and debt reduction strategy | Newly emerged in Q4; reflects a bearish market view juxtaposed with strong fundamentals, increasing management’s defensive stance. |
Production Curtailment Risks Due to Low Natural Gas Prices | Q1 highlighted severe issues with low natural gas prices (evidenced by Waha basis differentials and significant curtailment at Alpine High); Q2 and Q3 provided detailed curtailment volume estimates and outlined a structured curtailment strategy | Q4 stated that they do not anticipate any price‑related production curtailments in 2025, marking a notable improvement compared to earlier caution | Recurring with a positive sentiment shift; earlier curtailment risks appear mitigated or expected to improve. |
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Cost-Cutting Measures
Q: How confident are you in delivering cost cuts?
A: Management is confident in delivering at least $350 million in cost reductions over three years, primarily from capital savings, with $35 million already identified. They've begun by reducing G&A expenses, including cutting officer count by one-third, and are focused on driving efficiencies to enhance free cash flow. -
Capital Allocation Strategy
Q: Why prioritize buybacks over debt reduction with share price down?
A: Management is balancing both share buybacks and debt reduction, making meaningful progress on both fronts. They believe buying back shares leverages current shareholders, especially with the stock seen as compelling value, and many shareholders support the buyback strategy. -
Permian Production Outlook
Q: Explain softer Permian guidance and activity levels?
A: APA reduced Permian rig count from 11 to 8 rigs, focusing on sustainability. Production peaked at 140,000 barrels/day in October, declined to 128,000 by December, and is expected to average 125,000–127,000 barrels/day in 2025, maintaining a flat profile to enhance free cash flow. -
Permian Inventory Life
Q: How many years of inventory do you have in Permian?
A: Management is confident in their Permian inventory through 2029 and beyond, including the Callon assets. They expect to hold production flat with the current 8-rig program and continue adding more locations than they drill each year. -
Egypt Gas Drilling
Q: How are you balancing rigs between oil and gas in Egypt?
A: APA is maintaining 12 rigs in Egypt, shifting 2–3 rigs to gas drilling due to strong results and improved gas economics that are now on par with oil. Infrastructure is sufficient for now, but future expansion depends on exploration success. -
Suriname Development Progress
Q: What are the 2025 milestones for Suriname development?
A: The Suriname project is progressing well, with capital invested in long lead items like the FPSO. TotalEnergies is doing a fantastic job as operator, and they expect good progress on the development plan and exploration potential throughout the year. -
Free Cash Flow Allocation
Q: Will you adjust capital allocation if stock doesn't respond?
A: Management intends to continue buying back stock, believing in their asset base and upcoming free cash flow growth. They prefer investing in themselves rather than shifting strategy towards increased production or acquisitions. -
Egypt Receivables Situation
Q: What's the outlook for Egypt receivables collection?
A: Receivables in Egypt have remained stable over the past two years. Management expects to make progress in reducing past due balances this year, with commitments from the Egyptian government to address the issue. -
ARO and Decommissioning Costs
Q: How will ARO costs change over the next few years?
A: ARO expense is $100 million this year, mainly from Gulf of America, North Sea, and onshore U.S. Most regions will stay relatively flat, except the North Sea, where costs are expected to grow over the next 4–5 years. -
Egypt Gas Agreement Economics
Q: Explain the economics of the new Egypt gas agreement?
A: The agreement pertains to new gas, placing gas economics on par with oil on a full-cycle basis. This incentivizes shifting rigs to gas drilling, with improved pricing that accounts for any necessary infrastructure investment.