APA Q1 2025: Accelerated cost savings to $225M run rate, $126M FCF
- Solid free cash flow generation and improved balance sheet health: Q1 free cash flow reached $126 million and progress was made in reducing past due receivables in Egypt, underlining financial resilience.
- Enhanced cost efficiencies and drilling performance: Significant cost reductions—such as achieving $800,000 in savings per well in the Permian—coupled with improved drilling efficiencies, bolster margins and support a lower capital intensity going forward.
- Robust gas production performance in Egypt: The shift to gas-focused drilling, highlighted by an average realized gas price of $3.19 (above guidance), along with operational improvements, supports potential revenue upside.
- Regulatory/TAX risk: The results included a $76 million deferred tax charge in the U.K. from an increase in the energy profits levy, highlighting potential regulatory and tax headwinds.
- Credit risk in Egypt: Although progress on past due receivables in Egypt is noted, historically elevated past due balances in that region could still pose a credit and cash flow risk.
- Reliance on cost reduction gains: The company’s strategy is heavily dependent on maintaining lower capital spending through drilling efficiencies. Any deviation from this trend or unexpected operational challenges could negatively impact profitability.
| Metric | YoY Change | Reason |
|---|---|---|
Total Revenues | +35% (from $1,951M to $2,636M) | Increased segment performance across the board drove revenue growth, with robust gains in Oil (+39%), Natural Gas (+82%), and NGL (+50%). This combined effect, underpinned by increased production and favorable market conditions, lifted total revenues compared to Q1 2024. |
Oil segment revenue | +39% (from $588M to $816M) | Strong production performance in the U.S.—with a 50% increase in production volumes—coupled with effective drilling activity and benefits from acquisition synergies, significantly boosted oil revenue in Q1 2025 relative to Q1 2024. |
Natural Gas revenue | +82% (from $57M to $104M) | Enhanced market pricing and operational improvements led to a substantial uplift in natural gas revenue, overcoming the relatively lower performance in Q1 2024 and reflecting an overall boost in production efficiency and demand. |
Natural Gas Liquids revenue | +50% (from $131M to $196M) | Higher production volumes and improved price realizations in a favorable market climate drove the significant increase in NGL revenue, marking a strong recovery from the previous period’s lower levels. |
Operating Cash Flow | +198% (from $368M to $1,096M) | Operational efficiency improvements and robust commodity pricing, along with increased sales volumes, sharply boosted cash flows despite rising operating costs compared to Q1 2024. |
Net income attributable to common stock | +163% (from $132M to $347M) | Stronger operational results, fueled by increased production, merger benefits (e.g., Callon merger), and gains on debt extinguishments, significantly improved net income, even as higher depreciation and tax expenses partially offset these gains compared to Q1 2024. |
Current debt | Significant increase (from $2M to $131M) | A marked change in financing structure—likely driven by increased short-term liquidity requirements or working capital adjustments—resulted in current debt rising sharply in Q1 2025 relative to Q1 2024. |
Total property and equipment | +26% (from $10,143M to $12,780M) | Capital investments in oil and gas properties, along with expansion in infrastructure (e.g., gathering, processing, and transmission facilities), spurred this increase, reflecting strategic investments to support growing production and acquisition activities compared to Q1 2024. |
Shareholders’ equity | +108% (from $2,607M to $5,436M) | Robust net income performance combined with the issuance of common stock (adding $2,414M) significantly increased equity, although partially offset by dividends and treasury stock repurchases, leading to a more than doubled shareholders’ equity from Q1 2024 to Q1 2025. |
| Metric | Period | Previous Guidance | Current Guidance | Change |
|---|---|---|---|---|
Purchased Oil and Gas Sales | FY 2025 | $600 million, with $400 million from gas trading and about $200 million from the Cheniere LNG contract | No guidance provided | no current guidance |
Permian Production | FY 2025 | 8‐rig program with U.S. oil volumes expected in the 125,000–127,000 barrels per day range | No guidance provided | no current guidance |
Egypt Production | FY 2025 | Adjusted production expected to grow slightly despite a modest decline in gross volumes | No guidance provided | no current guidance |
Gas Prices | FY 2025 | Average realized gas price expected to increase from $2.96 per Mcf in Q4 2024 to at least $3.15 per Mcf in Q1 2025, with full‐year average of $3.40–$3.50 | No guidance provided | no current guidance |
Lease Operating Expense (LOE) | FY 2025 | U.S. operated LOE per BOE in the Permian expected to be about 20% lower than in 2024 | No guidance provided | no current guidance |
General and Administrative (G&A) Costs | FY 2025 | Total overhead costs expected to decrease by at least $25 million in FY 2025 | No guidance provided | no current guidance |
Capital Spending | FY 2025 | Capital budget expected to be $2.5 billion to $2.6 billion with front‐half weighted spending | No guidance provided | no current guidance |
Cost Reduction Initiatives | FY 2025 | Targeting $350 million in annualized cost savings with $100–$125 million in run rate savings expected by end FY 2025 | No guidance provided | no current guidance |
Free Cash Flow | FY 2025 | Generated $420 million in Q4 2024, with emphasis on further cost reductions and capital efficiency | No guidance provided | no current guidance |
Shareholder Returns | FY 2025 | Plans to maintain a 60% shareholder return program through share buybacks and dividends | No guidance provided | no current guidance |
| Metric | Period | Guidance | Actual | Performance |
|---|---|---|---|---|
Purchased Oil and Gas Sales | Q1 2025 | $600 million for FY 2025 | $597 million | Beat |
| Topic | Previous Mentions | Current Period | Trend |
|---|---|---|---|
Free Cash Flow & Balance Sheet | Consistent discussion across Q2–Q4 2024 on strong free cash flow generation (e.g., Q4: $420M in free cash flow, Q3: resilience amid Callon integration, Q2: high free cash flow returns) | Continued focus on protecting free cash flow amid commodity volatility, with emphasis on cost initiatives and strategic asset sales (e.g., NM Permian sale for $608M) to improve balance sheet health | Consistent focus with slight reinforcement amid market volatility |
Recurring Cost Reduction & Operational Efficiencies | Across Q2–Q4 2024, emphasis on achieving multi-million dollar cost savings, streamlined G&A, drilling and LOE improvements, and targets like $350M annualized savings | Continued expansion of cost-saving initiatives highlighted by increased targets (e.g., $130M savings and $225M run rate, $800K per well drilling savings) | Ongoing emphasis with improved operational performance and higher savings targets |
Sustained Focus on Gas Production (Egypt) | Q2–Q4 2024 featured discussions on gas production growth, new pricing agreements, and efforts to normalize receivables, with detailed notes on incremental gas volumes and associated agreements | Gas production now exceeds guidance, with a new pricing agreement leading to better price realizations and further receivables normalization; production volumes and pricing are improving | Consistent & optimistic, with improved pricing and performance metrics |
Ongoing Permian Production Sustainability & Efficiency | Q2–Q4 2024 emphasized rig count optimization (reductions from 11 to 8 rigs), maintained production levels, and notable drilling performance improvements (e.g., longer laterals, $800K savings per well) | Continued focus on Permian efficiency with further rig count reduction (from 8 to 6.5, potentially 6 later) while maintaining 125,000 bpd and demonstrating structural cost savings | Steady focus with further optimization boosting capital efficiency |
Integration of the Callon Acquisition & Synergies | Q2–Q4 2024 discussions highlighted integration progress with synergy targets up to $250M, improved drilling costs, overhead reductions, and streamlined operations on new acreage | Continued integration success with ongoing cost reductions, further drilling efficiency improvements, and enhanced inventory characterization supporting economic density | Maturing integration with sustained synergy realization and operational gains |
Capital Allocation & Leverage Concerns | Q2–Q4 2024 addressed a balancing act between share buybacks, asset sales, debt reduction, and mixed investor sentiment; discussions included significant share repurchases and asset disposal strategies | Q1 2025 reiterates the balancing of deleveraging (via NM Permian sale and revolver management) with opportunistic buybacks, reinforcing a pragmatic approach to managing high debt | Continued balancing act with strategic asset sales supporting debt reduction and shareholder returns |
Regulatory & Tax Risks | Q3 2024 featured extensive commentary on North Sea AROs, emissions control investments, and the energy profits levy, while Q2 had minimal focus and Q4 emphasized a deferred tax benefit from U.K. subsidiaries | Focus narrows to a $76M deferred tax charge due to an increased U.K. energy profits levy; emissions regulations and broader North Sea issues receive less emphasis | Shift in focus from broad North Sea regulatory challenges to targeted deferred tax issues |
New Exploration & International Opportunities | Q2–Q4 2024 discussed major projects like the Suriname FID (e.g., GranMorgu project with 220,000 bpd capacity) and Alaska exploration (e.g., King Street discovery and increased acreage) | Q1 2025 continues strong emphasis on exploration with accelerated Suriname spending (first oil expected in 2028) and detailed appraisal of the Alaska King Street discovery showing high-quality reservoir metrics | Robust growth potential persists, with exploration projects seen as transformative growth drivers |
North Sea ARO & Production Cessation Risks | Q3 2024 provided detailed focus on North Sea production cessation by 2029, outlining significant ARO liabilities and planned abandonment timelines; Q4 reinforced rising ARO costs | Q1 2025 omits detailed discussion on North Sea AROs, indicating a lower priority or strategic shift away from earlier heavy emphasis | Diminished emphasis suggesting a strategic shift away from North Sea retirement concerns |
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Cost Savings
Q: Savings doubled, why raise run rate?
A: Management noted controllable spend increased from $60M to $130M this year with plans to hit a $225M annual run rate, driven by early and structural savings that exceeded initial expectations. -
Debt Repayment
Q: How use asset sale proceeds for debt?
A: They explained that proceeds from the New Mexico sale will primarily be used to reduce debt, lowering revolving balances and improving the overall yield. -
Buyback Strategy
Q: Will buybacks continue amid debt focus?
A: The team reaffirmed a 60% return to shareholders framework, balancing debt reduction with opportunistic buybacks as liquidity permits. -
Permian Efficiency
Q: Can production be flat with fewer rigs?
A: They emphasized that reducing rig count from 8 to 6.5—and potentially to 6—is feasible to sustain flat production in the Permian through operational efficiency gains. -
Cost Run Rate
Q: What drove run rate increase to $225M?
A: Accelerated savings, notably $800K per well cuts and improved overhead, are propelling the annualized run rate to $225M, well ahead of schedule. -
LOE Controls
Q: How are LOE challenges being managed?
A: Management acknowledged slower-than-expected LOE savings due to inflationary pressures on compression and water disposal, expecting more meaningful progress later in the year. -
Breakevens
Q: What oil price covers CapEx and dividends?
A: They indicated that, with current savings and production targets, a $50 WTI is sufficient to cover both CapEx and maintain the base dividend. -
Capital Program Cut
Q: When will capital cuts occur due to oil prices?
A: The plan is to reduce rigs further if WTI falls to the low $50s, triggering capital program cuts to preserve cash flow. -
Egypt Shift
Q: What is the gas/oil production shift in Egypt?
A: In Egypt, a deliberate shift toward gas-focused drilling is underway, with a slight decline in oil volumes offset by growing gas production—targeting gas prices near $3.80/Mcf by Q4. -
Alaska Potential
Q: How promising is Alaska’s resource size?
A: They view their 325,000-acre Alaska estate as materially promising, pending further seismic reprocessing and appraisal to define its full potential. -
Asset Sale Effect
Q: Why sell New Mexico assets now?
A: The transaction was opportunistic, achieving attractive mid- to high 5x EBITDA multiples to monetize non-core assets for strategic debt reduction. -
LOE Offsets
Q: What examples offset LOE inflation pressures?
A: Management is renegotiating vendor contracts, optimizing pump routes, and revising terms for water disposal and compression to alleviate inflation impacts. -
Operational Cost Pace
Q: Were savings targets met ahead of schedule?
A: They confirmed that savings such as the $800K per well reduction have come in faster than expected, bolstering overall cost efficiency. -
Alpine Workovers
Q: Will workover rig requirements change for Alpine High?
A: They expect workover rig usage to remain similar, noting that new gas wells typically require less intensive maintenance compared to oil wells. -
Well Spacing
Q: How are well spacing strategies evolving?
A: The company is moving toward tighter well spacing with smaller fracs, which increases well density and expected recovery, though detailed targets remain dynamic.
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