Ladies and gentlemen, welcome to TotalEnergies' Third Quarter 2025 Results Conference Call. I now hand over to Patrick Pouyanne, Chairman and CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

Good afternoon, good morning, everyone. Before Jean-Pierre goes through the details of the third quarter results, I would like to make a few opening comments. Almost exactly one month ago, we updated our strategy during our Capital Markets Day in New York, and we had four key messages: consistency and resilience of our two-pillar strategy, strong and secure production growth in our Oil and Gas business, accretive cash flow generation, and capital discipline. I believe that this company’s strong results for the third quarter illustrate these key catalysts and highlight the value proposition of our consistent and profitable growth model. The strategy is clearly in motion and is translating into cash flow even in a more challenging environment. Indeed, despite oil prices dropping by more than $10 per barrel year-on-year, the cash flow for the third quarter increased by 4% and adjusted net income held steady. Why? Primarily for two reasons. First, the hydrocarbon production growth is a reality and highly accretive. The new project barrels coming online, such as Mero Fields in Brazil, deepwater projects in the U.S. offshore, going for oil, Tura, and Phoenix for gas have an average cash flow margin roughly twice higher than the base portfolio, contributing 170,000 barrels per day during the first nine months of 2025 compared to 2024. These new barrels have generated around $400 million of additional cash flow year-on-year. So growth volume around $200 million and higher margin, another $200 million. They have contributed to absorb the equivalent of $6 per barrel of decrease in Brent in terms of cash flow. That’s a strong demonstration that the disciplined investment framework, which includes strict sanctioning criteria, less than $20 per barrel technical cost and $30 per barrel breakeven for E&P projects is delivering its fruits. We expect, of course, that this cash flow tailwind from new high-margin barrels will continue as we work our way through our deep project queue. As a reminder, starting from 2025, continuing in 2026, the company is growing upstream production by 3% per year through 2030. The differentiation factor that stands out in our business model is that more than 95% of this production by 2030 is already either online or under construction and largely under lump-sum EPC contracts, which significantly derisks the cost. Our projects are in hand, and we are executing them. This year and this last quarter demonstrate that we are well in the delivery mode. Some people think we are borrowing, but we are borrowing for the good. Cash is growing. The second pillar of these good results has been the recovery of the downstream, contributing to the company's resiliency with cash flow up by almost $500 million. It is true that the refining margins were better. It's also true that we managed to capture them, thanks to good availability of our assets. Several turnarounds during the quarter executed on time, on schedule, and on budget, allowed us to reach our objectives. Marketing and Services continue to deliver consistent results, demonstrated by the priority given to value over volume in this segment being the right approach. In addition to highlighting the strength of our consistent strategy, this third quarter demonstrates that we are delivering in the short term, specifically on the second half of the 2025 plan laid out during the July earnings call, which included four key elements: the accretive production growth giving more cash flows, downward inflection in our net investments coming back to capital discipline, which decreased by $3.5 billion quarter-over-quarter, a reversal of the seasonal working capital releasing this quarter of $1.3 billion, and lastly, all these elements improved the gearing that is now close to 17% compared to next to 18%. The end result is that during the third quarter at $69 per barrel, the company generated excess free cash flow, cash flow including working capital variation more than covering net investment plus $4.5 billion of shareholder returns in the form of dividends and buyback. It leads me to shareholder returns. The company continues its strong track record of dividend growth. The Board of Directors decided to increase the first interim dividend by close to 8% in euro and more than 10% in dollars compared to 2024. Regarding buybacks, as announced on September 24, the Board of Directors authorized up to $1.5 billion of share buyback for the fourth quarter of 2025. Assuming annual cash flow between $27.5 billion and $28 billion, particularly supported by the better refining margin currently observed, the 2025 payout ratio is expected to remain around 56%. Looking forward, we expect to maintain strong momentum for the fourth quarter. Upstream production is anticipated to grow more than 4% year-on-year in line with this quarter. Net investments are expected to decrease quarter-over-quarter, particularly because we will deliver the disposal proceeds with $2 billion expected. The net of acquisition will represent a $1.5 billion cash inflow in the balance sheet. With another anticipated positive contribution from seasonal working capital, we anticipate to continue to strengthen the balance sheet with gearing forecasted to decline further to 15% to 16% at year-end. Last but not least, the Board of Directors has approved the roadmap to transform our ADRs into ordinary shares. We are happy to announce that we ordered JPMorgan today to launch the termination process of the ADR program with the objective of having ordinary shares begin trading on the New York Stock Exchange from December 8. This is an important milestone for the company, as it will allow a single class of TotalEnergies shares to trade with extended hours. It will effectively be a continuous listing from Paris at 9:00 a.m. to New York at 4 p.m. and 10:00 p.m. Paris time. We hope that this ordinary shares listing will be a clear catalyst for the stock in 2026 in both Paris and New York markets, and we intend to market these ordinary shares on the U.S. market even more actively than today. I will now turn the call over to Jean-Pierre, who will go through the details of the third quarter financials.

Thank you, Patrick. I will start by commenting on the price environment in the third quarter versus the second quarter. Brent averaged $69 per barrel during the third quarter versus $68 per barrel in the second quarter, up 2%, but down more than $10 per barrel compared to the third quarter of 2024. ETF averaged $11.3 per MMBtu versus $11.9 per MMBtu, down 5%, and the average LNG price decreased to $8.9 per MMBtu versus $9.1 per MMBtu, down 2%. On the other side, for refining, the European refining margin significantly improved to $63 per ton compared to $35 per ton during the second quarter, up close to 80%. In this price environment, the company reported strong financial results with third quarter 2025 cash flow increasing by 7% compared to the second quarter and adjusted net income increasing by 11%, thanks to the continued positive impact of the new attractive upstream barrels and strong downstream results reflecting the company's ability to capture higher refining margins in Europe. Overall, profitability remains strong with return on equity for the 12 months ending September 30 at 14.2% and ROACE close to 12.5%. Moving now to the business segments, starting with hydrocarbons. On a year-on-year basis, third quarter hydrocarbons production exceeded expectations and increased by more than 4%, making it the company's highest growth quarter so far this year. We anticipate that this trend will continue with fourth quarter hydrocarbon production expected to grow more than 4% compared to the fourth quarter of 2024, notably benefiting from the restart of Ichthys LNG in Australia. Turning to the quarterly results, starting with Exploration and Production, this segment generated during the third quarter of 2025, an adjusted net income of $2.2 billion, up 10% quarter-over-quarter in a similar price environment and outpacing quarterly E&P production growth of around 4%. Similarly, cash flow growth was robust at $4 billion, up 6% quarter-over-quarter. Importantly, our project portfolio is delivering new low-cost, low-emission oil and gas production that is accretive, with an average upstream CFFO per barrel roughly 2x the base portfolio. Regarding the E&P projects, we are progressing on all fronts. On the project side, we achieved first oil at the Begonia and CLOV 3 offshore fields in Angola, and we sanctioned Phase 2 of the redevelopment of the Ratawi oil field in Iraq, which is part of the GGIP project. With all phases of GGIP launched, we look forward to first oil for Phase 1 of the redevelopment in early 2026. On M&A, the company is consistently high-grading its portfolio. During the last earnings call, we mentioned expecting several E&P divestments in the second half of the year. In the third quarter, we divested two international blocks in Vaca Muerta in Argentina, which closed this quarter, and three satellite fields in Ekofisk in Norway, expected to close in the fourth quarter. Lastly, on exploration, we continue to reload the hopper to complement existing opportunities. This quarter, we announced new license awards in Nigeria, the Republic of the Congo, and Liberia. Moving to integrated LNGs, third quarter LNG sales of 10.4 million tons were essentially flat quarter-over-quarter as third-party purchases offset lower sales from equity production. Cash flow of $1.1 billion was in line with the second quarter in a stable price environment with an average LNG price of around $9 per MMBtu. Adjusted net operating income of $0.9 billion was down 18% quarter-over-quarter, primarily due to planned turnarounds at Ichthys LNG in Australia that impacted production by around 50,000 barrels of oil equivalent per day for the quarter. On the price outlook, forward European gas prices continue to be sustained at around $11 per MMBtu for the first quarter of 2025 and winter of 2025-2026 due to anticipated winter demand. Given the evolution of oil and gas prices in recent months and the lag effect on pricing formulas, the company anticipates an average LNG selling price of around $8.5 per MMBtu for the first quarter of 2025. On the advancement of our LNG strategy, we are pleased to continue to grow our U.S. presence with the recent FID on Rio Grande LNG Train 4 in South Texas and enhanced resilience in our LNG and gas-to-power strategy by acquiring interest in shale gas assets from Continental Resources in the Anadarko Basin in the U.S. Turning to Integrated Power, net power generation increased by 9% quarter-over-quarter to 12.6 terawatt hours due to increased output from flexible generation capacity in Europe. The value of TotalEnergies' unique integrated model is illustrated in the third quarter financials. Total cash flow from operations was $0.6 billion, up 9% quarter-over-quarter and in line with annual guidance. To provide more granularity in the Integrated Power financial performance, this quarter, we disclosed the split in cash flow between production assets, renewables, and gas-fired power plants on one side and sales activity, B2B, B2C, and trading on the other side, showing that each contributed equally this quarter. During Q4, the company has executed well on the farm-down side of its integrated power business model, which contributes to capital recycling and will generate a tailwind for free cash flow in the fourth quarter. The company signed an agreement for the sale of 50% of its 1.4-gigawatt renewable portfolio in North America and closed the sale of 50% of a 270 megawatt renewable portfolio in France. These deals have a combined cash impact of around $1.5 billion, and in this deal, TotalEnergies retains a 50% stake in the assets and will continue to be the operator after closing.

This is in line with our business model. As an important reminder, our attractive upstream growth is not the only contributor to the company's resilience. Integrated Power will take a key role in this too, since it is a differentiated and growing cash flow stream that is outside of crude cycles and has strong demand fundamentals. Moving to Downstream. As Patrick mentioned, during the third quarter, Downstream efficiently captured the high refining margins in Europe and contributed to the company's resilient financials. Third quarter adjusted net operating income of $1.1 billion was up more than 30% quarter-over-quarter. Cash flow of $1.7 billion was up 11% quarter-over-quarter, thanks to good availability of assets that allowed us to successfully capture improved European margins. In terms of free cash flow during the third quarter, downstream cash flow from operating activities exceeded net investment by over $2.5 billion. In Refining, the European Refining Margin Marker strengthened during the third quarter due to the tension on the diesel supply chain in the context of low inventories. Utilization was 84%, which was towards the high end of the guidance range of 80% to 85%, and it reflects efficient operations and planned turnarounds at Port Arthur in the U.S. and HTC in Korea. In Marketing & Services, results remain consistently strong, with high-margin activities offsetting lower volumes. Looking ahead, we anticipate refining utilization of 80% to 84% in the fourth quarter, which accounts for scheduled turnarounds at Antwerp and SATORP. Moving now to the company level and starting with working capital. As expected, we benefited from the working capital release during the third quarter, which was a $1.3 billion positive contribution to cash. Furthermore, for the fourth quarter, we anticipate another positive contribution. On net investments, they meaningfully decreased to $3.1 billion in the third quarter, which includes $0.4 billion of divestments, net of acquisitions. In the fourth quarter, as mentioned by Patrick, disposals are estimated to total $2 billion, including the closing of Nigeria and Norway divestments for exploration and production as well as farm-downs of renewable assets in North America and Greece for Integrated Power. We reiterate full year 2025 net investment guidance of $17 billion to $17.5 billion. Based on anticipated net investments and working capital, we expect gearing to decrease to 15% to 16% at year-end compared to 17.3% at the end of the third quarter. With that, Patrick and I are now available to answer your questions. And the operator, please open up the line for questions.

The first question is from Lydia Rainforth, Barclays.

I have two questions. First, could you clarify the current status of the tax issues in France? I noticed some headlines this morning concerning taxes on share buybacks and I'm curious about their implications. Second, Patrick, relating to your earlier point about growth in production, it appears to be strong, alongside growth in cash flow. As you consider 2026, could you provide an indication of how much cash flow might outpace production growth for next year? Please remind us of that as well.

Good morning, Lydia. Recently, there has been significant fiscal creativity in the French parliament. Clearly, the proposed full measures will not be effective, and it's wise to avoid reacting too strongly to the latest news. There was a super tax on multinationals that is outside the legal boundaries. France has established 125 fiscal agreements with various countries aimed at preventing double taxation, which is a firmly established principle. As the government has indicated, this is the proper approach, so we shouldn't be affected. Additionally, the constitution includes provisions that prevent excessive taxation from being approved or upheld. The political climate in France is quite unstable, and there's a lot of debate going on. However, I believe that ultimately we will find a sensible path forward. TotalEnergies does not generate a significant profit in France, so we will monitor this situation closely. Nonetheless, I am confident that the government will make appropriate decisions to sustain what we refer to as the supply policy. Wealth creation, production, and results generation must precede any discussion about distribution. I recognize that the current situation in France is influencing TotalEnergies' share price, but we must remember that we are a global entity. Approximately 90% to 95% of our cash flows and results come from outside of France. This differentiates TotalEnergies' profile from other French companies, and the market should take that into account. Regarding 2026, I will provide a more detailed response in February during our annual results meeting. I anticipate a growth rate exceeding 3% for that year. While I do not have all the cash flow figures yet, they will depend on new production coming online. Some of the new production from 2025, such as Brazilian production, will impact 2026 significantly. I expect another accretive effect, but its magnitude will require patience. We are currently focused on delivery. We have achieved production growth exceeding 3%, and this year it could approach 4%. By the end of 2025, we anticipate 3.5 to 4%, and for next year, at least 3%. Our aim is to generate accretive cash flow as part of our roadmap, not just for 2025 and 2026, but over the next five years. If we fall short, we have reassured you during our New York presentation that we will deliver an additional $10 billion in free cash flow across all segments over the next five years.

The next question is from Michele Della Vigna, Goldman Sachs.

Congratulations on the strong growth. Two questions, if I may. First, I was wondering if you feel like you're able to capture the extraordinary refining margins we are seeing, and how the improvements to your Port Arthur and Donges refineries are progressing? And then secondly, I was just wondering what you're seeing in terms of disruptions of the Russian volumes following the latest sanctions and if you start to see an impact on the physical market through your trading and optimization division?

Thank you for this question, Michele. To be honest, when I read our press release again, I think we are a bit bearish on the oil price and the refining margins. The refining margins we captured since the beginning of October for the last month is around $75 per ton. So when we guided you it's above $50, I think we are a little shy. In fact, it's fundamentally linked because we begin to see real market impact from the last Russian sanctions. I think the market is underestimating what it means to have U.S. sanctions on two large Russian companies at the core of trading Russian oil. With Europe targeting countries considered dangerous like India, Turkey, and China, if you trade oil or products with these countries, you could be under sanction. The market reaction today in trading hours is more cautious. We see that everyone is taking this risk very seriously, including secondary sanctions, which might come. I see some impact, and the refining margins today are more around $100 per ton than the $75 as an average. This is linked to the fact that the sanctions will require rerouting volumes and finding more expensive ways to supply crude oil and products worldwide. I would say I am more bullish about the situation than what we wrote a few days ago. TotalEnergies stopped trading any Russian oil since the end of 2022; we penalized ourselves compared to others, but I believe it was the right strategy to comply with Russian sanctions. So capturing the refining margins is for sure positive. The good news from the third quarter is that we managed to do it. We had a turnaround in Port Arthur, which is now back online. Donges is as well is running, and it's not fully equipped yet, but we will be fine. The fourth quarter, we will have two turnarounds, one in Antwerp and one in SATORP. I expect this will be compensated yet again by the other assets and the fact that the margins are higher. I'm positive. When I provided a guidance of $27.5 billion to $28 billion, I may have been too conservative by stating $27 billion in New York. This guide considers the elements to maintain marginal profitability, where all elements of refining, chemicals, and Total are dedicated to capturing these good margins.

The next question is from Doug Leggate of Wolfe.

I wonder if I could start with your upstream margin. The volume guidance is again pretty strong for Q4. But what we're observing is that your upstream margin seems to be moving up as well as the volumes. I'm trying to understand what happens as the mix changes going forward. For example, Iraq never historically had great margins. How do you see the margin mix continuing as the growth trajectory sustains over the next several years? That's my first question. And my second question, if I may, is a quick one. Oil appears to still be in a very technical market. We all see the oversupply, but it seems to keep bouncing around that $60 level. I guess my question is, if you ended up with better cash flow than you thought, when you reset the buyback, what would be the first call on cash? Would it go to the balance sheet to continue deleveraging? Or would it go to the higher end of the buybacks?

The second question is clear; it will go to the balance sheet. So that answer is clear: it will go to the balance sheet. I observe that and I have spent quite a lot of time with investors in the last month, and clearly, I would say, long-term investors view deleveraging the balance sheet as important. To be countercyclical, you need to have a strong balance sheet. Regarding upstream margins, no, Iraq is in fact a good contract. Historically, this was not the case. We had good contracts when we came back to Iraq; it’s a matter of risk and reward, and specifically, the Iraqi contract is quite reactive to oil price changes. We can capture some upside and benefit from quite low-cost production, so the breakeven is low. The Iraqi barrels are contributing to the increase; they are accretive. I can give you, but you may recall our figures showed an average around $19 to $20 per barrel. Today, new barrels are more between $30 and $40 per barrel. Thus, we have excessive growth in upstream, and I think we will continue to see the free cash flow from upstream move quicker than production growth.

The next question is from Biraj Borkhataria, RBC.

Firstly, nice to see that production growth being accretive. That really is a differentiator. Two questions. The first one is on the divestments for the year. I know you mentioned Nigeria in the $2 billion. I believe there were two deals that you're planning to do, one of which wasn't approved. Could you just outline whether the SPDC side, that sale is in the $2 billion, or is that on top of the $2 billion? Secondly, recently, you signed a letter with a group of CEOs around European competitiveness. I was just wondering if you could share whether that letter has catalyzed any kind of response in terms of policy?

What is the second question? Sorry, I didn't catch it well. Oh, okay. I understood. European competitiveness. First, regarding divestments, I will be clear with you. The $2 billion amount is coming from several sources. We intend to finalize some of these, and we have already completed a few, but we are aiming to close them. We have signed agreements, and it’s just a matter of completion. The Bonga divestment in Nigeria, the satellite Ekofisk field in Norway, and renewable assets in the U.S. are all part of this, alongside another project in Greece. There is an additional $300 million that will be announced soon. So that's a total of $2 billion. This does not include the SPDC joint venture divestment, not only because it was approved but also because we could not finalize it due to certain conditions on our side. We are currently in discussions with two new buyers who seem serious, and we will not be able to close before this quarter. This is beneficial for us as it fits into next year's plan. Based on my observations, divesting E&P assets generally takes time. Sometimes it can happen quickly, like our divestment in Argentina, but at other times it may take longer. Regarding the European Competition letter, we have noticed that European leaders are paying attention to our requests. We have had discussions with some European commissioners who took the letter seriously. I believe we might be asking too much, but I see it as a wake-up call from these 40 CEOs. Together with the Siemens CEO, I am a spokesperson for this initiative. We have expressed the viewpoints shared during meetings between French and German CEOs. Some of these discussions have also drawn comments not only from European CEOs but also from the U.S. Energy Secretary and Qatar’s Energy Minister, urging a reassessment of certain legislation. This matter is significant, and we are striving to contribute to European growth. However, to achieve this, we need to voice our concerns when we feel that circumstances are evolving.

The next question is from Martijn Rats, Morgan Stanley.

I've got two, if I may. First of all, what I thought has been really surprising this year is the strength of new LNG FIDs. A year and half ago, many were writing reports about the surplus in the LNG market in the second half of the decade, and yet 2025 has been a near-record year of new LNG capacity to be commissioned. Total still has a few projects that need final decisions. I was wondering if you could share with us your thoughts on the strong number of new FIDs and how it impacts your decisions regarding future LNG FIDs? The second question is about the shares and the equivalence between Paris shares and U.S. shares. I wonder if this could impact your buyback program execution, particularly if this is in place from December 8, if some of the buyback could be done in New York-listed shares as a means to avoid some proposals floated in the French parliament.

Regarding the second question on ADR, no, it does not impact the execution of the buyback program at all. I remind you that the ADR conversion is about 9% to 10% of our shares. The buyback program will be executed on the Paris Stock Market, and not on New York listed shares, because it would be strange for us to buy back from New York where we want to give life to the New York market. The buyback program will not avoid any tax proposals, by the way. The tax proposals are amusing proposals. Again, there are some principles. When the President, Aurelien, tried to impose a 3% extra tax on dividends, it was canceled by the European Union and by the French Constitutional Group. All companies have recouped the money they took. There are some limits in the constitution, and it’s clear. We must separate political debates that are very creative from the reality of rule of law, and I know that there are some limits. I would trust the government as I consider what I observe because the higher the proposed taxes, the more I’m assured that they won’t go through. Now on FIDs, regarding new LNG projects, I'm not unsure how many FIDs exactly because announcements fluctuate due to project revivals. You have a flow coming from projects in view of finances. Other projects may benefit from good financing, while if financing is expensive, you risk the project’s value. We see strong prospects for our LNG investments, but we have to be disciplined about which projects to prioritize. We postponed Cameron '24 due to high CapEx. We need to be disciplined in investment decisions. We have also lifted the force majeure on Mozambique; the figures mentioned about $25 billion are not accurate. The actual investment was about $20 billion, and we expect to deliver the project by 2029.

The next question is from Kim Fustier, HSBC.

A couple of weeks ago at an industry conference, you mentioned that the LNG market is getting more competitive and it's harder to make money in trading. I was wondering if you could provide any more color on this, and how much of the decline in LNG trading profits would you ascribe to heightened competition versus the more normalized conditions, lower volatility, lower spreads, et cetera? I also wanted to come back to the EU sustainability rules; hypothetically, what would be your options if some LNG supply is deemed to be non-compliant?

To be clear, I think we made a demonstration in New York; the message is not that LNG trading profits declined. We told you that there were exceptional trading profits in 2021, 2022, 2023, and that we are back to a normal environment with lower volatility. The results of 2025 on integrated LNG are consistent with those of 2024. Thus, we are still stable. Our outlook for LNG trading profits from TotalEnergies will hinge largely on the growth of volumes as our business remains asset-based, rather than trading on speculation; it’s tied to production. There are more trading hours entering the LNG business because of our profitability during earlier periods, but I don’t see a significant decline in LNG trading profits just yet; rather, we are simply normalizing. I prefer to have solid profits on my North Sea gas and a little less volatility in trading. Regarding competitive sustainability rules, the concern surrounding compliance was about the penalties you might face if a judge finds you guilty of non-compliance, which could lead to sanctions of up to 5% of worldwide turnover. It’s a proportionately large penalty regarding rules we want to adhere to. We are focused on ensuring all our LNG produced, especially from the U.S. and Qatar, is compliant with the duty of vigilance law.

The next question is from Matt Lofting, JPMorgan.

I wanted to follow up on your earlier comments on the refining portfolio; 80% to 84% utilization in the fourth quarter looks towards the lower half of the historical range. From a near-term perspective, planned turnarounds and maintenance need to be undertaken. But when you look forward into 2026, how do you see the normalized throughput of the business now, and has there been any deterioration in that normalized level?

I think we are cautious. As I said, the $50 per ton maybe reflects a little insecurity; perhaps the 80 to 84% is simply influenced by Antwerp and SATORP’s large planned turnarounds presently. That said, it impacts global delivery from our portfolio. Keeping utilization around 82% this quarter compared to last quarter can be a reasonable average considering higher margins. For next year, I’d expect to operate between 84%-86%. Importantly, we experienced some difficulties previously before the Port Arthur turnaround, now executed. If refining margins remain strong, we can generate even higher returns.

The next question is from Irene Himona, Bernstein.

My first question is on marketing, if I may, because your unit margins were up this quarter. Could you discuss the drivers of that margin improvement? Is it structural or temporary? My second question concerns the partnerships on AI and a global data platform. I want to ask whether it is correct to consider these partnerships a way to broaden your digitalization effort that has been ongoing for a number of years.

Yes, I'll address the second question first. Since 2020, we established a digital factory allowing roughly 300 data scientists. This led to a bottom-up approach for deploying new technologies. However, advancing on a worldwide basis was challenging. We have made a strategic decision to consolidate with Emerson for data connectivity, a project expected to take 2.5 to 3 years to implement fully. Simultaneously, we initiated a large digital program in E&P with Cognite. Ultimately, we aim to enhance AI implementation and boost operational efficiency. For 2025, we have laid out a roadmap for scaling, intending to yield additional revenue streams from improved processes. Addressing marketing, the margin improvement derived from a strategy focused on value over volume. Mature markets hinder significant growth, and we recognized the importance of prioritizing profitability. Our previously existing low-margin operations and logistics shared operations have been reduced to improve margins. The continued focus on enhancing Marketing and Services margins is a structural strategy within the business model.

The next question is from Christopher Kuplent, Bank of America.

Patrick, I wonder whether we could discuss another area of French creativity. There is an idea floating around that we should remunerate electricity or wholesale power prices differently. What can you tell us about the current appetite for signing new PPAs? How has that market evolved considering the regulatory backdrop? You've recently signed a project deal with RWE in France but have CapEx left to go in Germany on the offshore wind front. Can you provide context summarizing the risk-reward behind taking that regulatory risk? Could you also give any updates on how quickly we should expect news from Mozambique now that force majeure is lifted?

On Mozambique, we lifted the force majeure; we expect government approval of our new plan and budget while remobilizing contractors to execute the project by 2029. Regarding the first question, I’m not in favor of regulatory approaches; we prefer markets where signing PPAs is the best way to commercialize assets. In Europe, it is crucial to sign during development. Recently, we signed a contract in France at $65 or $66 per megawatt-hour, which can be adapted if CapEx escalates, thus safeguarding our investment. I believe European markets are incredibly unique, driven by specific rules. When discussing with authorities, I see little appetite for changing the electricity market. While the discussions may be vigorous, we must rely on political leaders to make informed decisions. Europe must invest more in renewable energy, gas-fired power plants, and an improved grid to ensure security of supply.

The next question is from Lucas Herrmann, BNP.

And another slightly generic question, but I wanted to ask for your thoughts on the part of the complex that is really having a difficult time, chemicals. The extent to which when you talk within the industry, you’re seeing movement to try and restructure businesses so that we might actually see profits start to improve. If you could provide some indications regarding how much of the profit within the Refining and Chemicals business comes from chemicals given the tough environment?

We are a refining and petrochemical company, making crack ethylene and polyethylene basics. The situation in petrochemicals is challenging; over the past five years, China's cracker capacity expanded significantly, leading to near-self-sufficiency while impacting global patterns. Our naphtha crackers in Europe face tough competition from U.S. and Middle Eastern producers. Since my tenure as CEO, we have invested in two crackers — one in Port Arthur and the other in Saudi Arabia. We are shutting down some less-relevant operations, such as the recent decision in Hamburg. In terms of the proportion of profit, I don’t have a precise answer. However, overall, it is not a major contributor to our cash flow. Most is generated from refining and trading rather than chemicals; thus, I don’t have any miracle recipes.

The next question is from Peter Low, Rothschild & Co. Redburn.

The first was just on integrated power. The ROACE has been below 10% for a few quarters now. How confident are you of hitting your 12% target? What are the steps to get it up to that level in the coming years? Secondly, regarding the proposed EU ban on Russian LNG imports from 2027, I understand you'd expect to be able to divert your Yamal cargoes to alternative markets outside the EU. Is that still your base case?

First question; as stated, we noted it’s a five-year journey from the current figures to 12% ROACE. We acknowledge that current investments hold some non-productive capital. As we continue to grow, we convert non-productive assets into productive ones. We also plan to rationalize and industrialize our operations to enhance value utilization. We have been concentrating our Integrated Power investments into strategic markets. For ROACE, we are also clear on which projects won’t contribute to exceeding that target. For the second question, there has been new regulatory movement that needs clarity regarding scope. We need to observe answers about this renewed regulation to understand its implications. For sure, no further Russian LNG in Europe is the aim, but we must confirm their scope of ban before committing further.

The next question is from Paul Cheng of Scotiabank.

Two questions. I want to go back, Patrick, in your answer to the question of adoption of AI. You think that is a fairly sizable investment. Can you quantify how big the investment will be over the next couple of years and whether you have sufficient talent within your organization or need to hire? It seems that it is challenging to obtain strong AI talent; what are your targets for AI over five years? The second question is on Iraq. Can you inform us about the situation on the ground? Security seems stable for deploying people. However, what bottlenecks exist for Iraq to increase production significantly? Are there concerns that Iraq could become a major growth area, depressing oil prices?

For AI, the investment I mentioned will represent around €300 million or $350 million worldwide. It is significantly invested across massive data platforms. Regarding talent, we have several experts, including firms such as Emerson, Aspen/Tech, Cognite, and around 300 people from our digital factory. We will utilize existing employees but may need to grow resources. We are considering establishing a competency center in India as part of our growth strategy and overall cash-saving program. There are many exciting use cases, mainly on the energy front, enhanced efficiency through improved machine learning and AI tools. For Iraq, we have executed contracts and feel secure in the country, particularly in the Basra area where conditions are good. However, there are still challenges regarding security and efficiency on the financial side. We have observed that many companies expressed interest in contracts. Still, we are focused on ensuring sufficient returns due to past lessons about investments not meeting demands.

The next question is from Henri Patricot, UBS.

Just two on exploration. I think you have a new Head of Exploration since the start of the month. Any changes to expect in your exploration approach? Also, can you provide an update on plans for Namibia and South Africa's exploration over the coming months?

I’ve been consistent about exploration; my budget remains $800 million to $1 billion. I set that rule upon becoming CEO because expenditures don’t always yield more discoveries. You need to be efficient and compel your exploration team into a productive search. Kevin led the team well over the last ten years. Nicolas Mavilla is our new head of exploration, joining us from a successful exploration company. He’ll have the freedom to guide teams in innovative directions. As for Namibia, we have existing exploration to continue there, while in South Africa various legal contexts complicate operations. There have been increased legal hurdles when attempting to drill, which create difficulties and uncertainties around future investments. We hope South African leaders will ease the regulatory burdens so we can continue to explore and develop successfully.

The next question is from Jason Gabelman at TD Cowen.

I wanted to ask on CapEx trajectory. Organic CapEx has been a bit volatile; what drives that quarter-to-quarter volatility? Other peers have stable CapEx peaking in Q4. Moving forward, can we consider the current level a better pace? Or should we expect more quarterly volatility? Also, regarding production ramp-up next year, you've previously indicated lower reinvestment rates in 2027, which implies higher cash flow in 2027 along with new production. How should we visualize the cash flow ramp for 2026 and into '27?

Our commitment is an annual CapEx budget. Since I've been CEO, there has been strong consistency in the annual CapEx budget. What we stated is a budget of $17 billion to $17.5 billion. We are typically within this budget. Each quarter's volatility will naturally occur given project completions and new operations transitioning into production. In 2024 further, you expect efficiency in balancing quarterly shifts based on property transitions. As advised, please await details on cash flows and reinvestment rates in February during the annual results meeting. A key component is that for 2027, we anticipate a reinvestment rate decrease from 70% down to 50% as you can see in prior presentations. The capex has guided to $16 billion next year; this is crucial for planning.

There are no more questions registered at this time.

Okay. Thank you all for your attendance. I hope the analysis you've completed will reflect positively on the stock price. It has not currently demonstrated that, but we are delivering. This is the message: we have a consistent strategy. We are executing, delivering, and frankly, the Board of Directors and I, as CEO, are quite pleased with this quarter's results. It demonstrates that everything we explained throughout the quarter and year is in delivery mode; our free cash flow will increase. Thank you for your attendance.

Ladies and gentlemen, this concludes the conference call. Thank you for your participation. You may now disconnect.