Mark Wilson

Mark Wilson asked about the greatest improvements from third-party areas, such as upstream partners or oilfield service contractors, that have assisted Eni's delivery, beyond its internal capabilities.

Answer

Claudio Descalzi (CEO, Eni) emphasized Eni's long-standing strategy of insourcing core competencies, increasing R&D investment (7 R&D centers, 1,100-1,200 R&D personnel), and developing in-house technology across drilling, reservoir, seismic, and development. He stated that this approach, rather than reliance on external contractors, has been the main reason for Eni's success in time to market and project delivery.

Mark Wilson asked about the third-party areas, beyond upstream partners or oil field service contractors, where Eni has seen the greatest improvement to assist its delivery, such as drilling, reservoir characteristics, or E&C cycle time.

Answer

CEO Claudio Descalzi emphasized Eni's strategy of insourcing main competencies since the 2000s, increasing R&D investment (7 R&D centers, 1200 people), and developing internal technology in drilling, reservoir, seismic, and development. He stated that this focus on internal capabilities has revolutionized Eni's time to market and is the main reason for its success.

Mark Wilson asked about TechnipFMC's volume capacity, specifically for Subsea 2.0, given the consistent $10 billion inbound orders, growing opportunity list, and low CapEx as a percentage of revenue.

Answer

Doug Pferdehirt, Chair and CEO, TechnipFMC, stated that the Subsea opportunity list is expanding and accelerating, leading to expectations for inbound order growth in 2027 and beyond. He highlighted the dramatically expanded client set and the enablement of new companies by the simplicity of iEPCI 2.0 direct awards.

Mark Wilson highlighted the ExxonMobil Hammerhead Subsea 2.0 award as validation and asked for TechnipFMC's view on installation capacity in the market, specifically the Saipem 7 merger, its impact on vessel infrastructure, and any submissions TechnipFMC made regarding that process.

Answer

Doug Pferdehirt, Chair and CEO, clarified that TechnipFMC's scope in Guyana is separate from installation, which is bid separately by ExxonMobil. Regarding the Saipem 7 merger, he stated regulators and customers will make decisions, and TechnipFMC provides clarifications on market segmentation when asked. He reiterated that their strategy of 'relentless pursuit of reduction of cycle time' effectively creates more capacity with existing assets, focusing on efficiency and higher returns rather than acquiring more assets.

Mark Wilson inquired about the validation of TechnipFMC's offerings, specifically the ExxonMobil Hammerhead Subsea 2.0 award, and the company's perspective on installation capacity in the market, including the Saipem 7 merger and its potential impact on vessel infrastructure.

Answer

Chair and CEO Douglas Pferdehirt confirmed the Hammerhead award as validation of their evolving technology. Regarding the merger, he stated regulators and customers will make decisions, and TechnipFMC provides clarifications when asked. He reiterated that their focus on cycle time reduction effectively increases existing fleet capacity by improving efficiency, rather than acquiring more assets.

Mark Wilson asked about the competitive landscape for TechnipFMC's iEPCI and Subsea 2.0 offerings, particularly in Brazil where Petrobras uses its own standards, and the potential for broader adoption there.

Answer

CEO Douglas Pferdehirt acknowledged Petrobras's use of its own standard but noted FTI remains optimistic about future Subsea 2.0 adoption. He stressed that other major operators in Brazil, such as Shell and Equinor, are already adopting FTI's iEPCI and Subsea 2.0 model for their projects, proving its value in the region. He stated that outside of a few specific regional standards, Subsea 2.0 has broadly proliferated the market.

Mark Wilson of Jefferies asked about the drivers behind the increasing size of large project awards (over $1 billion) and sought confirmation of TechnipFMC's claimed one-year cycle time advantage over competitors.

Answer

CEO Douglas Pferdehirt explained that larger project sizes are a result of clients returning to higher-quality offshore reservoirs and choosing TechnipFMC for its proven ability to deliver with schedule security. He emphatically confirmed the one-year cycle time advantage is still valid and stated the company is relentlessly focused on shortening it further.

Mark Wilson from Jefferies asked about the pecking order of BP's 12 exploration discoveries, emphasizing Bumerangue's potential, and whether BP would be comfortable appraising Bumerangue through 2027 at a 100% working interest.

Answer

Gordon Birrell, Executive Vice President of Production and Operations, highlighted BP's rich hopper of opportunities, including Namibia and Trinidad, but acknowledged Bumerangue's potential to be very material. He stated that BP could go through the full appraisal phase at 100% working interest but would consider a partner if it adds value, emphasizing no rush to dilute.

Mark Wilson from Jefferies asked about the pecking order of BP's 12 exploration discoveries, specifically the importance of Bumerangue, and whether BP would appraise Bumerangue through 2027 at 100% working interest.

Answer

Gordon Birrell, Executive Vice President, Production and Operations, highlighted BP's rich hopper of opportunities, including 23 years of production life. He stated Bumerangue has potential to be very material but wouldn't give a rank order, as all projects compete on economics. He confirmed BP could go through appraisal at 100% working interest but would take a partner if it added value, also mentioning Namibia and Trinidad discoveries.

Mark Wilson asked about the work scope for the Boomerangy flow test, questioning if it would be prolonged and costly, whether appraisal would be 100% BP-funded or if exploration costs would rise, and the timing for bringing in a partner.

Answer

Murray Auchincloss (CEO, BP) clarified that the Boomerangy flow test, expected in late 2026/early 2027, will focus on well productivity, with CO2 sampling already done. He confirmed a partner would be sought after appraisal for value, and the exploration budget remains around $500-$600 million, staying within the $13-$15 billion capital frame.

Mark Wilson inquired about the scope and cost of the Bumerangue flow test, specifically if it would be prolonged to test multiple areas and CO2 mix, if it's within the EUR 600 million exploration budget, and if overall exploration costs would increase.

Answer

Murray Auchincloss (CEO, BP) stated the Bumerangue flow test (Q4 2026/early 2027) would primarily focus on well productivity, as sampling and sidewall core analysis are already complete. He confirmed a team is working on an early production scheme, dependent on flow test results. BP plans to bring in a partner after the appraisal well and flow test for value. He noted the exploration budget is around EUR 500 million-EUR 600 million for about 15 wells annually, and BP will remain within the EUR 13 billion-EUR 15 billion capital frame.

Mark Wilson asked about Shell's forward plans for its UK North Sea business combination (Enduro JV), whether it's an investment area, and how expectations for fiscal changes in the UK influence its strategic view of the portfolio.

Answer

Shell CEO Wael Sawan expressed excitement for the Enduro JV, emphasizing the need for predictable and progressive tax systems in the UK to attract investment. He noted the JV combines the strengths of Equinor and Shell, with a development runway and follow-up opportunities if conditions are right. CFO Sinead Gorman reiterated Shell's sacrosanct 40-50% CFFO distribution policy and its capital allocation framework, which considers company performance, macro outlook, and competition between organic opportunities, inorganic opportunities, and buybacks.

Mark Wilson asked about Shell's plans for its UK North Sea business combination (Enduro JV), whether it's considered an investment area, and expectations for fiscal changes in the UK, assessing the strategic importance of the portfolio.

Answer

Shell CEO Wael Sawan expressed excitement for the Enduro JV, highlighting its development runway and asset base for follow-up opportunities. He emphasized the need for predictable and progressive tax systems to attract capital for UK North Sea investments, hoping for improved fiscal conditions. CFO Sinead Gorman reiterated Shell's consistent capital allocation framework, prioritizing the 40-50% CFFO distribution target while also considering organic and inorganic growth opportunities.

Mark Wilson of Jefferies asked if securing a gas sales agreement is the most critical next step for the GTA Phase one plus expansion. He also questioned whether Kosmos should become the operator of the Jubilee field, given its demonstrated expertise with new seismic data.

Answer

Chairman & CEO Andrew Inglis confirmed that clarity on a gas sales agreement is a necessary step before an FID on GTA Phase one plus, but he views it as an addressable issue rather than a barrier. On the topic of Jubilee operatorship, Inglis emphasized the strong, collaborative partnership with Tullow Oil, stating that Kosmos is effectively contributing its subsurface expertise without needing a formal change in operatorship.

Mark Wilson asked for more detail on the better-than-expected subsurface performance at Tortue and inquired about the physical and financial mechanics of the domestic gas obligation, including its connection to NOC loan paybacks.

Answer

CEO Andrew Inglis explained that initial flowback data from development wells indicated greater connected reservoir volume than previously mapped, which could reduce future drilling needs. He clarified that the national oil companies are responsible for building the domestic gas pipeline infrastructure, meaning Kosmos has no capital liability. If the domestic gas is not taken, more gas is available for Kosmos to sell as LNG.

Mark Wilson from Jefferies asked for the expected timeline to reach the 1.5x leverage target and the company's capital allocation priorities thereafter. He also inquired how long the Tortue reservoir could produce at planned rates before requiring additional wells.

Answer

CFO Neal Shah projected reaching the 1.5x leverage target towards the second half of 2026, at which point the company will reassess the balance between further debt paydown and shareholder returns. Chairman and CEO Andrew Inglis added that new wells at Tortue are 'several years away' as current well capacity significantly exceeds requirements, and future drilling would not be a significant draw on capital.

Mark Wilson sought clarification on U.S. Gulf of Mexico production levels, the 2025 outlook with new Winterfell wells, the company's leverage target for initiating shareholder returns, and the final steps for the Tortue FPSO startup.

Answer

CEO Andrew Inglis confirmed current U.S. GoM production is ~20,000 boe/d *without* the curtailed Winterfell wells and will be slightly higher in 2025. CFO Neal Shah reiterated the leverage target of <1.5x before considering shareholder returns. Inglis added that the Tortue FPSO is very close to handover from Technip to BP operations, a final step before first gas.