Total Revenue

Up ~10% (from $2,308M to $2,531M) " "

Higher U.S. revenues and improved commodity pricing drove overall revenue growth, partially offset by lower international contributions. The prior period’s lower U.S. production volumes were surpassed due to new well additions and acquisitions.

U.S. Segment

Up 36% (from $855M to $1,167M) " "

Increased drilling activity and synergies from recent acquisitions boosted oil production and realized prices, contrasting with subdued activity levels in the prior period.

North Sea Segment

Down 67% (from $419M to $137M) " "

Operational challenges and planned turnarounds reduced production, whereas the prior period benefited from more stable run times. Weaker realized prices also compounded the revenue decline.

Egypt Segment

Down ~6% (from $805M to $754M) " "

Slightly lower oil prices and deferred drilling activity reduced revenues compared to the prior period, which saw steady production gains. Continued focus on free cash flow and cost management limited further declines.

Operating Income (EBIT)

Down from $1,048M to -$143M " "

Higher expenses and one-time charges (including transaction and reorganization costs) offset revenue gains. In the previous period, stronger realized prices and lower costs contributed to higher EBIT.

Net Income

Down from $459M to -$223M " "

Increased depreciation, depletion, and amortization plus non-core charges and weaker North Sea performance outweighed revenue improvements. The prior period benefited from higher commodity prices and fewer special items.

EPS (Diluted)

Down from $1.49 to -$0.71 " "

Lower net income stemming from operational and one-time charges drove EPS down, whereas the previous year saw stronger commodity pricing and higher margins. The shift to negative earnings per share reflects the impact of those charges.

Capital Expenditures

FY 2025

no prior guidance "

$2.2–$2.3B (U.S., Egypt, North Sea) + $200M Suriname + $100M exploration "

no prior guidance

Rig Count

FY 2025

no prior guidance "

8 rigs in the Permian Basin, 12 rigs in Egypt "

no prior guidance

North Sea Production

FY 2025

no prior guidance "

Expected ~20% decline year-over-year "

no prior guidance

Cost Guidance

FY 2025

no prior guidance "

Per-unit LOE, G&A, GPT, and interest costs down 10–15% year-over-year "

no prior guidance

Egypt production

Emphasized flat to slightly down production outlook, managed by rebalancing rig counts and waterflood projects. " " " " "

Slight decline in gross oil output; maintaining 12 rigs and focusing on waterflood to sustain volumes. " " "

Consistent topic with a sustained approach to flatten declines and improve stability.

Gas expansions

Negotiations on higher gas prices and potential gas projects previously mentioned; expansions were contingent on improved economics. "

Added a gas-focused rig in Egypt under a new gas price agreement, targeting low-hanging fruit for incremental volumes. " "

Ongoing focus with greater clarity under a new pricing framework, spurring more gas activity.

Permian production

Consistently strong performance; meeting or exceeding guidance, with robust oil growth and plans for 9–11 rigs. " " " "

Sustaining ~130 Mbbl/d oil output with an 8-rig program; curtailing gas at Alpine High due to weak Waha prices. "

Still a main driver; short-term curtailments but continuing as a centerpiece of U.S. operations.

Integration of Callon acquisition

Synergy estimates rose from $225M to $250M, spanning overhead, operational, and financing; emphasis on capturing efficiencies quickly. " "

Integration largely complete, ~$250M in cost synergies realized; debt reduction efforts a key focus. " " "

Advanced from partial to near-full synergy capture; now prioritizing debt paydown.

Suriname exploration progress

Consistent year-end 2024 FID target; prior calls also indicated first oil by 2028 with further technical work ongoing. " " "

Progress toward FID on Block 58 with a $10.5B gross cost; potential first oil around 2028. "

Increasing detail on cost and timeline; poised for long-term growth impact.

Alaska exploration results (King Street)

Discovery at King Street validated the petroleum system; past calls highlighted high-quality sands and acreage expansion. " "

Preparing to spud another well in early 2025, with ~300,000 acres of largely state land. " "

Ongoing enthusiasm for exploration; moving from discovery to further appraisal.

North Sea and Gulf of Mexico AROs

Prior updates showed $815M Fieldwood-related GOM exposure and partial references to North Sea abandonment timing. "

Detailed a $2B North Sea ARO liability with a $1.2B NPV after tax benefits; no GOM update. " " "

Greater clarity on North Sea costs; GOM largely static in current disclosures.

Shareholder returns vs debt reduction priorities

Historically returning ≥60% FCF to shareholders; emphasis on paying down debt post-Callon acquisition and targeting credit rating improvements. " " "

Prioritizing debt reduction with proceeds from asset sales; shareholder returns still governed by ~60% FCF framework. " "

Heightened focus on lowering leverage, though shareholder distributions remain important.

Commodity price environment

Significant Waha differentials in prior quarters, with some negative pricing episodes; curtailment strategies to preserve value. " "

Weak Waha pricing led to short-term production curtailments; extreme volatility noted at times. " " "

Continuously challenging Waha hub dynamics remain a key operational and marketing factor.

Evolving sentiment on sustaining production vs pursuing growth

Balanced discipline across earlier quarters, with rig count adjustments to sustain output and avoid overspending. " " "

Maintaining stable volumes in Permian and Egypt, cautious about adding rigs in a soft price environment. " "

Steady shift toward production stability over aggressive expansion in near-term plans.