Ladies and gentlemen, welcome to TotalEnergies' second quarter and first half 2025 results conference call. I now hand over to Patrick Pouyanné, Chairman and CEO, and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead. Good afternoon or good morning, everyone. Before Jean-Pierre goes through the details of the second quarter financials, I would like to make some few opening comments. We are facing an unstable geopolitical and macroeconomic environment, which has been dominated during the quarter by the Israel-Iran 12-day war and also the tariff war between the U.S. and some commercial partners. In this context, oil markets have been volatile during the second quarter, with prices broadly fluctuating between $60, $70 per barrel, an average of $68 per barrel. With a short and ultimately modest increase during the Iran crisis, we put prices reaching $81 per barrel at the highest point. We could consider, in our view, that this is quite a limited price response to these major crises, and somewhere it is a signal that the oil market is well supplied, in particular fueled by OPEC Plus' decision to unwind some voluntary production cuts and also facing a weaker demand linked to the global slowdown of economic growth. In such a context, and Jean-Pierre will detail that in a few moments, this quarter, TotalEnergies once again demonstrated the company's robustness thanks to its balanced and consistent strategy. It also thanks, and it's more important, to its differentiated and unique energy production growth profile, both in oil and gas and in electricity, and that drives cash flow growth as well as attractive and is a basis for attractive shareholder returns through cycles. Starting first with our first pillar, oil and gas. The first half of 2025 production was up more than 3% year on year, demonstrating that we are well on track to achieve our 2025 upstream production growth guidance of more than 3% versus 2024. As you know, it will be even longer up to the end of the decade, this 3% growth. It has been supported, and it's also very important, by startups of high-return projects such as the Ballymore Field in the U.S. or Mero 4 in Brazil, which, by the way, was one quarter ahead of schedule. Now, Begonia and CLOV 3 in Angola just came on stream to further feed the Q3 and H2 growth. As I said, importantly, this production is coming from this new project that is attractive, increasing the upstream cash flow CFFO per barrel by around $1 per barrel as an average during the quarter, which is in fact quite impressive given our large production base. We are also continuing to manage this portfolio, focusing on our projects on which we meet our low-cost, low-emission criteria, and divesting some non-core, higher-cost projects. During Q2, consistently with this strategy, we divested non-prorated interests in non-core, higher-cost projects in Nigeria, Bonga, and Brazil, Gato do Mato. During the second quarter, we have also reloaded the exploration portfolio by acquiring exploration permits in the U.S., in the U.S. Gulf, in Malaysia, in Indonesia, and Algeria. On the LNG front. The big news of the second quarter is that we continue to strengthen the portfolio by signing a 1.5 million-ton LNG offtake agreement from Rio Grande LNG Train 4. We will become shareholders of this train as well. We have also taken, I would say, an option potentially on the future projects located on the Pacific coast of Canada, which gives access to Asian markets and will benefit, by the way, from very cheap gas. In Canada, in Alberta, Canada. On the second pillar, as you can have observed, our integrated power continues to deliver solid results and solid cash flows to close to $600 million. It is on track to achieve also its annual guidance. In line with our strategy, we also continue to unlock value in our power business by progressing farm downs. We have sold during the quarter 50% of our 600 MW portfolio of renewable assets in Portugal, and there is more to come in the second half. The Q2 downstream results benefited from a positive seasonal effect of marketing and services activities, which have done very well, which in fact are stronger, with stronger results year on year. Despite near-term improvements in refining margins, to be honest, it is a small improvement in the second quarter. Refining chemicals are still facing some headwinds either on the operational side. Two refineries were not at the optimum, I would say, efficiency, Donges and Port Arthur. Also on the market side, it is more for the polymer business, which is facing overcapacities in the market. Moving to CapEx, during the first half of 2025, net investments totaled $11.6 billion, including $2.2 billion of net acquisitions, in particular the acquisition of VSB. I confirm today that for the full year, we anticipate the net investments will be within the $17-$17.5 billion guidance range, given the disposal program planned for the second half of the year, which is already well engaged. In upstream, beyond our stake in Bonga, Nigeria, as announced, we have in fact this last week approved some binding offers for our unconventional oil license in Argentina and for two other E&P assets, which will represent globally $1 billion of cash flow. We are also working, and the E&P team is working hard to close our divestments of onshore Nigeria before year-end. This represents next to $1 billion. In integrated power, we are very well advanced for the farm downs of the 1.5 GW portfolio in the U.S., a 250 MW portfolio in France, and a 400 MW in Greece. These three farm downs will represent net divestments of CapEx of around $1.5 billion. The gearing stood by the end of June at 18%, increasing quarter to quarter, primarily due to net investments being weighted towards the first half over the year, in particular because of the disposal proceeds, but it was anticipated. Working capital, small build on first half and working capital built on the first half. Excluding the seasonal effects of working capital and the investment base, normalized gearing is 15%. I will conclude my remarks with the shareholder distributions. The message of the board is clear. We maintain shareholder distribution at high level. I would say, as a payout could stand around 55% in 2025, which is, as you remember, quite above the guidance of more than 40% full cycles. First, on dividends, the ordinary dividend is our number one capital allocation priority. We continue our track record of attractive growth. The board of directors approved the second interim dividend of 2025 of EUR 0.80 per share, which is an increase of 7.6% compared to 2024, and it is up 25% versus pre-COVID. I would like to underline that in U.S. dollar terms, considering the evolution of the U.S.- euro exchange rate, this increase is more than 10%, and it was 8% in 2023, 8% in 2024. U.S. shareholders have the benefit of that. I would like also to underline that this dividend yield is the best among the majors. Comforted by the ability of the company to reach its 2025 underlying growth objective, in particular on energy productions on both sides, the upstream, which continued to deliver good results quarter after quarter, and also integrated power, while maintaining a strong balance sheet, the normalized gearing at 15%. The board has decided to continue share buybacks for up to $2 billion in the third quarter. The board will continue to monitor the buyback on a quarterly basis, looking to the evolution of the macro environment, but also on possible anticipations on the oil, gas, refining, petrochemical markets. We intend to give you more colors on the buyback scheme at our investor day end of September. Now I will turn the call over to Jean-Pierre, who will go through the details of second quarter financials. Thank you, Patrick. I will start by commenting on the price environment in the second quarter, which was overall weaker quarter over quarter. Brent averaged $68 per barrel versus $76 per barrel in the first quarter, so down 10%. TTF, the European gas marker, averaged $11.9 per million BTU versus $14.4 per million BTU in the first quarter, down 18%. The average LNG price also decreased to $9.10 per million BTU versus $10 per million BTU in the first quarter, down again by 10%. For refining, the ERM, European refining margin slightly improved to $13.5 per ton during the second quarter, but as mentioned by Patrick, still remained at a low level. In this context, the company reported robust financial results, demonstrating the strength of our business model and of our operations. We have adjusted net income of $3.6 billion and cash flow from operations of $6.6 billion for the second quarter, which were supported by attractive production growth. Profitability remained strong with return on equity for the 12 months ending June at 14.1%. Now, moving to the business segments, starting with hydrocarbons. As anticipated, second quarter production was slightly lower than the first quarter due to plant maintenance. However, on a year-over-year basis, the second quarter marked yet another increase in upstream production, which amounted to a strong 2.5% thanks to new projects, startups, and ramp-ups. On the cost side, the company continues to be a leading low-cost operator, with upstream operating costs at $4.9 per barrel for the first half of the year. Looking forward, we expect hydrocarbon production in the third quarter to increase by more than 3% compared to the third quarter 2024. Turning now to exploration and production. This segment generated second quarter 2025 adjusted net operating income of $2 billion and a cash flow of $3.8 billion. Importantly, our project queue is delivering new low-cost, low-emission oil and gas that is attractive, with an average upstream CFFO per barrel equivalent that is roughly two times the base portfolio. In fact, during the second quarter, production from the new project improved the upstream CFFO per barrel equivalent by around $1 per barrel equivalent, generating something like $180 million more than if they had come from the base portfolio. On a cumulative basis for the first half 2025, the extra CFFO generated by new projects totaled close to $300 million. On integrated LNG business, our sales were stable at 10.6 million tons for the second quarter, and the company achieved $1 million of adjusted net operating income and cash flow of $1.2 million for the second quarter, reflecting the 10% increase in the average LNG selling price related to declining crude price, as well as low market volatility for gas trading activities. Forward European gas prices continue to be sustained at around $12 per million BTU for the third quarter and for the 2025-2026 winter period due to storage replenishment in Europe. Given the evolution of oil and gas prices in the recent months and the lag effect on pricing formulas, the company anticipates an average LNG selling price of $9-$9.5 per million BTU in the third quarter. On integrated power, the net power generation increased 28% year-on-year to 11.6 TWh due to growth in renewable sources and the impact of the 1.3 GW CCGT acquisition in the U.K. closed in 2024. Integrated power adjusted net operating income was close to $580 million, up 14% year-on-year, and cash flow was $562 million. First half 2025 cash flow totaled $1.2 billion and we're on track to achieve the annual cash flow guidance. Lastly, we are progressing on the company's farm-down strategy, which optimized, as you know, capital allocation. During the second quarter, the company sold 50% of a 600 million watt portfolio of renewable assets in Portugal. As Patrick mentioned, there is more to come with the 50% farm-down of a 1.5 GW portfolio in the U.S., 400 MW in Greece, and 250 MW in France. Moving now to downstream. Although refining margin improved during the second quarter to $35 per ton, overall, we remain in a global weak price environment. In this context, downstream reported second quarter adjusted net operating income of $0.8 billion and cash flow of $1.5 billion. Results benefited from positive seasonality in marketing and services business, with results higher year-on-year. In refining, the utilization rate increased in the second quarter due to improved efficiency and low maintenance, but the results suffered from some operational difficulties at Port Arthur and Donges refineries, as well as weak petrochemical margins as the polymer business is facing a global glut of new capacity in China and in the U.S. Looking ahead, we anticipate refining utilization in the range of 80%-85% in the third quarter 2025, which reflects scheduled maintenance at Antwerp, Port Arthur, and HTC in Korea. In terms of downstream environments, in petrochemicals, we see continued pressure on pricing from the record incremental production capacity that was placed in operation in 2022 and 2023. In SAF business, imports to Europe have significantly increased, pushing prices down and likely impacting bio margin for the rest of the year. Moving now to the company level. On working cap, the company reported a $0.5 billion increase in working cap requirements, mainly due to the unfavorable effects of declining prices on tax liabilities and payments during the quarter for the capital gain tax from divesting the German distribution networks to Alimentation Couche-Tard. This was partially offset by the seasonal release on gas and electricity supply activities in Europe after a strong build in the first quarter. Note that the increase in the first half 2025 working cap requirements of $4.9 billion is essentially at the same level that was reported one year ago in the first half 2024. Looking ahead, the company expects that most of the seasonal working cap builds that were observed in the first quarter 2025 should be released in the second half of the year. On net investment side, so net investment totaled $6.6 billion in the second quarter, which notably included the closing of VSB acquisitions. For EUR 1.6 billion and $11.6 billion for the first half of the year. We anticipate full-year net investments to be within the guidance range based on planned disposal during the second half of the year, as Patrick mentioned. That means that the gearing by end of June is impacted by something like $2.6-$2.8 billion of CapEx. With that, Patrick and I are now available to answer your question. Now can open the line. Thank you. Thank you. Ladies and gentlemen, we will now begin the question and answer session. As a reminder, if you wish to ask a question, please press star and one on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking a question. If you wish to cancel your request, please press the star and two key. Once again, please press star and one if you wish to ask a question. The first question is from Michele Della Vigna, Goldman Sachs. Please go ahead. Thank you very much. Two quick questions on the LNG market, actually. You continue to grow it very strongly with both long-term contracts and new projects. I'm just wondering, at what point do you think that it will become really difficult to sign new long-term supply contracts with customers? It feels like we're starting to build a bit of an oversupply for the coming years, and that the oil linkage is probably approaching that 12%, which starts to become less attractive. I just wanted your view there also because it would be interesting to see at what point we start to see a slowdown in new FIDs. Related to that, in the U.S., how do tariffs impact the cost of building new LNG plants there? There's various elements. I think the steel tariffs probably are the most relevant ones. Does that make you a bit more cautious to do an FID on a new LNG project in the U.S., or that's actually manageable in the context of your portfolio? Thank you. Thank you, Michele. You are right. There is clearly a big increase of LNG supply, which will come on stream, as we said, 2027, 2028, 2029. For me, 2026 still will be quiet because these projects are always a little difficult to ramp up, I would say. Projecting Qatar is more or less on time. The first train we expect from NFE is mid-2026. Then every six months, a new train. 2026, for me, will not be so much impacted by this new capacity. From 2027, you will see clearly an impact. That is why we, since last year, we decided to move to a clear strategy, which is to sign some medium-long-term contract linked to Brent because I am more optimistic on the Brent oil price than on the, I would say, GTF and GKM spot gas price. And we continue to have some success on that. We have announced this year quite a number of million tons last year, and we will continue. The question is, why does the customer behave like that? I think the customer, they have been, I think, honestly caught in 2022 by some, the hike. We are in a world which is honestly quite volatile. The geopolitics play a game in the market more than ever. It is not just supply and demand. By the way, not easy for traders today to manage this geopolitical risk, even if I would say all traders within TotalEnergies have done very well in the second quarter despite this environment. That is true, but I think the buyers continue to look at it as a way to hedge themselves. They want to, yes, it is true, it is better to sign at 13%, but at 12%, I fully agree with you. By the way, when you have a long-term contract at the end for a company like TotalEnergies, it is not only a percentage which counts. It is also all the optionalities. Because we have a large portfolio, and then we can, do you have the capacity to redirect the cargoes? That is a lot of things which are also important for us. Around a medium-long-term contract, there is more value to extract than just a pure formula. That is why it is important to be a portfolio company. I think, in fact, one of the advantages of the position of TotalEnergies when we meet these buyers, they see us as a portfolio company and not just as a point-to-point, I would say, seller and buyer. It is not project one. We are today marketing Papua LNG, sorry, marketing Papua LNG. We have some good results in some Asian countries because of the location. This dynamic is still there, and we continue to work on that. U.S. tariff, I have some good news for you and for us because we have a real figure. We know we are just, we are not far from approving sanctioning, but not us. Rio Grande next decade is not far from. Sanctioning the 2024, maybe 2025. There have been some, I would say, EPC contracts discussed with Bechtel. I will tell you, Michele, I was a little afraid, and where do we land with this tariff impact? Finally, of course, there is some inflation, but it's less than 10%, I would say. It's very reasonable. For me, again, the next decade wants also to commercialize LNG, so it's more a question of marketing. I think 2024 is full. 2025 is not yet, but things are moving on, and it's their job. Fundamentally, from this real case, I would say that we manage, and I think it's also the dynamic when you have a very good EPC contractor, we see some advantage. I think Rio Grande LNG is a success story. 2021, 2023, if we are able to continue on 2024 and 2025, then there are also some synergies there. Your answer to you, I would say, on this specific case, we are comfortable. We don't see much impact on the tariff. We will see more impact on the tariff, I think, on topics like batteries because batteries, you have to import. Most of the cells in the world are manufactured in China. Even if you build the modules in the U.S., you have to import the cells. This type of business will be more impacted. From this perspective, I think my colleagues who are drilling U.S. shale oil are probably more impacted by the increase of tariff on the steel because you understand they are using some specific steel. Most of this steel is impacted. Probably the cost of a well in U.S. shale is more impacted than our own business in the U.S. today. Thank you, Patrick. The next question is from Biraj Borkataria, RBC. Please go ahead. Hi. Thank you for taking my questions. The first one is just on working capital. If I look at these quarterly changes in working capital over the last few years, it looks like the magnitude, both up and down on a quarterly basis, has been increasing over the last few years. I am thinking about the period, sort of 2017, 2018 to now. I am just trying to understand if that is something we should expect going forward, whether it is the growth of the power business or something else, or if there is any particular reason for that. The second question is just a quick one on the buyback. In Q1, you said up to $2 billion buyback. I noted you did $1.7 billion this quarter. Was that just a timing issue or liquidity or a conscious decision to do a bit less there? Any color on that would be helpful. Thank you. The second question, it's easy. You have found the right reason. It's more a question of timing. We have the $2 billion have been bought by the 13th of July. It was a question of liquidity. So no message for the $1.7 billion. We will catch up according to the guidance of the board. Okay. We are working on it. It's easy to answer the second question. It will give you insurance on that. On the first one, the quarterly, look, I think Jean-Pierre told you. Made a remark. If I'm looking to, at the end of the first half of 2024, first half of 2025, we had both years build of around $5 billion. In 2023, it was around $4 billion or $3.5 billion. There is an increase. Because the more we develop this B2C business in gas and power, which is growing in the companies, the more we have a seasonal effect, which is that, in fact, the people are using our, I mean, somewhere are burning a lot of using electricity, consume, sorry, consume electricity and gas during winter times. As their bill is spread about 12 months, we have a working capital effect, which is we catch up. That's increasing a little. Having said that, just to be clear with you, last year, at the end of last year, we told you in our working capital, the green went down to seven. We made a modification. We told you, be careful. There is an exceptional, I would say, positive element of around $1.5 billion. For me, what I'm expecting between today and the end of the year is a $5 billion build of the first half should be, in fact, erased by $3.5 billion, I would say, if I don't have any other exceptional. Normally, we should, like we've done the previous years. Jean-Pierre has explained, has shown us a nice graph in front of us. Maybe one day we'll share it with you, with the months' worth of seasonality. We, of course, presented that to the board, and we are comfortable with the type of metrics I just gave you to give you more insights of what happened. Okay. Thank you. That is also why, to be honest, when we put together to the board, and I am just repeating what I said, this working capital analysis plus these, I would say, CapEx, which have been more weighted on the first half because of the disposal. And because, as I try to, I mean, I hope you are convinced, I should give you a list of all the disposals which we are committed to and which we have really binding offers on, which we are now translating that in SPA, the board considered that all these elements give him confidence to maintain this buyback at $2 billion. Knowing that, as an average for the year, we are at $70 per barrel. Like, by the way, we made a presentation in February at $70 per barrel, giving you some guidance. The $70 per barrel has been the average for the year. Today, when I am looking at the screen, I have a $70. People can say low bearish on demand, the supply, but at the end of the day, this is a market. We keep trust on that. The next question is from Irene Himona Bernstein. Please go ahead. Thank you. Good afternoon. Patrick, you told us before that the $2 billion quarterly share buyback is affordable at $70 and at reasonable market conditions. When you look at the balance sheet with the current 15% normalized gearing, what is the normalized gearing range, let's say, that you would see as reasonable? In other words, how high would that normalized gearing have to go to remain acceptable in a $70 environment? My second question on integrated gas and LNG, the CFFO in the division declined about 6% in the first half, year on year. Are you confident in the cash flow guidance you provided for that division out to 2028? Thank you. Thank you. To be clear, at $70, we told you at the beginning of the year that the target guidance for the gearing was around 12%-13%, if I remember well. There were some few assumptions in it. In particular, there was the idea that the downstream could target a cash of $7 billion. To be honest, today, we've done $2.5 billion the first year. We think the downstream will improve because the margins, third quarter margins on refining are always better. It is the case. We have margins today above $60 per ton. It's good. Second, I'm really confident that the performance of the two assets I've mentioned will improve. Teams are working hard. I would say maybe not $7 billion downstream, maybe $6 billion, but we are not so far. I have one. You have some. I would say, for me, at the end, we are still targeting 14%-15% gearing by the end of the year. The normalized gearing for us at 15% is a good guidance. The board is comfortable with 15% at $70. This is a message I think we deliver to you. Again, it's not only the gearing, the balance sheet we have, we know that there is volatility. It's more we observe the markets. Today, as I said, there are some pros, some cons. We not only look to the oil markets. Gas markets, I would say we are quite confident for next year, but also petrochemical markets, the downstream markets. There are some good reasons to think that the diesel spread is quite strong, in particular with all what happens around Russia. It's a global approach that we take. At $70, 15%, we are comfortable to maintain this buyback level. The second question, and I understand your question, why? I mean, we will, of course, give you more information by end of September, September investor meeting. We come back, traditionally, with the data of our five-year business plan. We'll, of course, update you on both. Growth or upstream, the LNG part as well. I can tell you that I think last year we gave you some guidance, which were something like $6 billion at $60, $7.5 billion at $80. The figures that I read recently from our five-year business plans are confirming this guidance. We'll give more color by the end of September. I'm confident we can do that. Honestly, the small miss, but I observe as well, to be clear, it's not so big. It's linked to, in the gas, in fact, gas markets where in Europe, but we have no volatility. We've seen quite a good volatility in the oil price, moving from $60 to $70, even $81. Our traders were really able to capture that during the second quarter. Congratulations to them. On the gas, when you look to the gas price in Europe, the TTF, I think, was moving from 11 to 12, maybe a little 12.5. There was little volatility. By the way, again, it's true, I've seen some comments from one of our peers that in this type of market, where sometimes there is a, it's not only supply and demand, it's more political impacts. Traders are a little more cautious not to take direct directional positions, which could be hit by a tweet. It's a little more difficult for them to analyze the market beyond the fundamentals, which is their job, normally, fundamentals to do. That's the point. There will be no change in the guidance. Our LNG business will grow, will deliver the growth from Qatar, from the U.S., and it will positively impact the CFFO. Thank you, Patrick. The next question is from Martijn Rats, Morgan Stanley. Please go ahead. Yeah, I wanted to ask you too. First, if I can pick you up on the point of refining, because of course, I read your outlook statement, which looks quite cautious on the outlook for refining, talking about long-term structural challenges. We have really quite encouraging refining margin on the screen as of today. Over the last couple of weeks, there's a lot of strength in middle distillate. Reading the outlook statement, what was shining through was a clear belief, I think, that this is sort of temporary. I was wondering if you could say a few words about, in your mind, what is explaining this recent bout of strength, but also how long this could last and how it could dissipate. We're closing a lot of refineries in Europe this year. I kind of thought that the remaining refineries of TotalEnergies, at least in Europe, actually should have quite a decent 2026 as well. I was hoping you could give a few thoughts on that. Also, I wanted to ask if you could give us an update on Mozambique and the project there and what we can expect going forward. Okay. Refining is an interesting question, I think. In particular, what has clearly happened today is that there is a diesel driver in the market to explain why refining margins are quite good. We think that stronger diesel prices have become a persistent feature on the global market. It is linked in particular to all that has happened around Russia flows. In fact, the Europeans have banned, have stopped buying Russian petroleum products early 2023. That means that the source of diesel, because Europe is fundamentally at a deficit of diesel, so we are obliged to import, the sources of diesel are coming now from the Middle East or from U.S. refineries further away. It has increased the cost of all that. I would say the last decision of the European Union, which is to ban imports from refineries even outside of Russia, and targeting some refineries, I think, in India or Turkey, which would use Russian crude oil to be refined to make diesel, is impacting, again, I would say, increasing the scarcity of sources of diesel for Europe. It is an additional signal which goes in the same direction. On diesel as well, as you have observed, diesel is easier to produce from heavier crude oil than light crude oil. In fact, the mix of the crude oil, the basket, is lighter and lighter because of shale oil. That means that it is more difficult, more costly to produce diesel. It is another source, which is, again, I would say, and you have also more NGL when we speak about liquid. NGL plus light oil, at the end, is not good for making diesel. That is, again, pushing diesel prices up. I think that is the fundamentals. If I try to analyze the diesel fundamentals, which are supporting this market. In Q3, of course, is the driving season, so there is more demand. I think the news coming, people have underestimated this news from the EU banning imports of products from non-Russian refineries if they use Russian crude oil. That, of course, is pushing up. There is something for me more structural there. It is a margin business. It is not like oil, but this is the point. On Mozambique. On Mozambique, I'll be clear, we are working. It is a major project. I would say we are working in order to ensure a very strong alignment between the government of Mozambique and the investors. This is, for me, absolutely necessary before we engage to have a very strong alignment between the Mozambican authorities and the investors. Thank you. The next question is from Lydia Rainforth, Barclays. Please go ahead. Thank you. And good afternoon. Two questions, if I could. Firstly, just picking up on the downstream and the structural side, can you talk about the potential you see from the digital AI deployment that you announced, I think it was with Emerson, and how quickly do we start to see results on that? And then secondly, if I can come back to the buyback, I mean, I get the idea that the rest of 2025 looks covered by divestments, that gearing does not get worked, that you can afford the $2 billion for the quarter. But you did talk about the payout ratio being high at 55%. So I am just thinking about, as we go into sort of next year, how you are thinking about that and why you want to stick to that $2 billion buyback. Is it just because you are seeing the value in the share price, or just really why you still think that is the right level? Thanks, Patrick. Okay. The first question, thank you for the question of AI and digital. We are now moving. Going, I would say, from words to action. This announcement with Emerson on data digital is quite fundamental. In fact, we have decided to invest in, I would say, a real-time data platform. We need to structure all this data. It will be done not on a pilot basis, but on a worldwide basis for all our assets in downstream and refineries, also in upstream. The same platform, which is the innovation platform, which behind the platform, we are developing with Emerson some software, which the objective is to, I would say, enhance the value we can extract from the assets. There are two programs. One on advanced process control and upstream. Advanced process control is technologies which are used in refineries for long, which we are not using in the upstream. We will use them on our upstream assets. We think since my upstreamers have discovered it, they are fans of that. This is a smoke. We are also working on the downstream to going beyond advanced process control in order to make more developments on software based on data with AI. It is really for us, and I'm a believer that AI is not only cutting costs for, I would say, general services, it is enhancing the value of the assets because we could better monitor these machines. This is a rule of purpose. No, for TotalEnergies, it is an action. We are also, by the way, working with another company, and there will be an announcement soon to another additional AI platform, which will come on assets. That is good because digital, for me, it really is a source of future competitiveness in our operations. We are also establishing, by the way, within OneTech, a full digital line in order to—it's not a question of IT people. It is a matter of business people to put it at the heart of the technology of the assets. The digital line will be established within OneTech with strong teams. That is for this one. On the second one. When we think about buyback, firstly, why do we buy back? Just a fundamental. It is just a matter also of good management of the money of Jean-Pierre. What I observe is that today, Jean-Pierre has been able with his teams to make a bond issuance in euro recently, again, at around 3.5%. We borrow money at the depth is at 3.5%. At the same time, but I hope it will not be for long, but considering the share of value share, we serve the cost of the capital, if I say the dividend over the share value is around 6%. Why do I buy buyback? It is not because it is just—I cannot demonstrate to anybody. I am saving some money from one side, and I am borrowing at the lower side. But the fundamental, there is no—and on the top of it, when you buy back, as I said, it's a base of increasing future dividends. It's a virtuous circle. There are the two fundamental reasons. The question, we benefit from a strong balance sheet. In the past, it was a 30%-40% gearing. Today, people have questions because we moved from 10%-15%. Okay. I'm a little bit clear. We should look at it, and I see titles in newspapers when I'm a little surprised, as if it's problematic. No, I think we need to monitor that. For me, again, there is a point. I answer to a question, one day, what is reasonable? I think I said 65%-70% is reasonable. That means that at a certain point beyond 60%-65%, maybe not reasonable. We'll see that. I will come back to you because I know that, unfortunately, we will give guidance to all of you who want always more color on it. The reasonable guidance is maybe not enough for you. End of September, we are working with the board. We'll come with you with, I would say, a more—not fully detailed—we like to keep some capacity to maneuver, but we'll give you, answering your question in particular, because we are at 70%. We are no more 80%. Some people in the market look to 60%. I think it will be time to come back with you with a clearer picture. Today, we stick to what we said. We have $70 for the first hull, $70 on the market, and the $70. We're committed to $2 billion at the beginning of the year. Even if we have a little lower cash flow from the downstream, it does not change dramatically. It's not missing a billion-dollar miss; we'll not change the full picture like that. The next question is from Doug Leggate, Wolfe Research. Please go ahead. Thank you. Good morning, everyone, or good afternoon over there. Patrick, I think the working capital discussion has been fairly well debated, but I'm wondering about the CapEx guide for the year. You're running pretty hot, obviously, with the acquisitions year to date versus the $17 billion-$17.5 billion guide. What visibility can you give us on disposals to get you back into that range in the second half of the year? Okay, Chris. Doug, sorry. I think I gave you in my speech, I tried to give you a lot of visibility, more than I ever have done, I think. I think the first time, because I knew that you will have to be secured with that, because you—but generally, when I say something, we execute it. I know it's a matter of credibility. What I told you is that we had already Bonga, which has been divested. I told you that we have approved with the executive committee some binding offers from other assets, in particular, our own conventional oil license in Argentina with a good offer, and two other assets that I cannot disclose because it's not yet public, but it will come. It represents $1 billion. We have another $1 billion coming from closing the onshore Nigeria divestments, which was announced last year. In Nigeria, it's always longer, but we are working on it. Of course, we have all the farm downs on the integrated power, which will represent $1.5 billion. When you make the math, it's 1 + 1 + 1.5 makes $3.5 billion. It's more or less the guidance of the year for CapEx was a net between acquisition and divestments of zero, which is what I told you at the beginning of the year. On the, I would say, organic CapEx, we are in line. To be honest, I assigned even a small challenge to my team, telling them that $17 billion- $17.5 billion is within the range. It would be better to be next to 17 than next to 17.5. It's a challenge. I'm not sure that we will manage, but we are working on that. It's early here. I guess I missed the details. Sorry, Patrick, but thank you for that. I give you a--again, you should benefit of it because I'm not sure I will do it again to give more visibility. Okay. My follow-up is a little detailed. You bought or you took the 25% of CEPSA's block or share in Block 53 in Suriname. And our understanding is that from one of your, basically your FPSO providers, that things might be moving a bit faster there. Can you offer any insight on the timing, your latest thoughts on GranMorgu, and what Block 53 means for the resource recovery and perhaps the plateau production? I mean, on GranMorgu, honestly, I do not know who is telling you we are moving faster. I would be very happy if we deliver the first hull by beginning first half 2028, what we committed. No, I think they are moving. I recently went to KL, to Kuala Lumpur, where I met my teams. There was good news and some a little more cautious news. I need to take all that. No, honestly, for me, there is no reason to change, no reason to accelerate. Block 53, there was a small discovery there. I mean, we are in the range of 50 million barrel. We had the opportunity to capture it for quite a decent amount, quite very reasonable ones. CEPSA wants to exit from upstream, so we have the options buyers. We will connect it. I think we have the plateau of GranMorgu is at 220,000 barrel per day. These machines, generally, when we were designing them for 220,000, they can easily go up to 240,000. It is not, 10% is generally the case. If we can connect these type of things, it will give more value. For me, as I always told you, since we sanctioned GranMorgu, GranMorgu varies a lot of hydrocarbons, including around the we made over discoveries that we put behind. There will be a planning. We are discussing. We are trying to look to come back on some and to appraise some of the previous discoveries. I have asked my teams because even if there is maybe not enough to make a second FPSO, for sure, the objective is to extend the plateau and to make a higher plateau to create a lot of value from this infrastructure. It was a very good opportunity for us to make things. Being inside will smooth all these type of unitization stories. We will be a partner of it. It will help a lot with our colleagues in order to move these resources quicker. Thank you very much indeed. The next question is from Christopher Kuplent, Bank of America. Please go ahead. Hi there. Thanks for taking my questions. Just two quick ones, please. On FX, can I ask? Your dividend has become almost 10% more expensive since the start of the year in dollar terms. Is that still irrelevant in the greater scheme of things, Patrick? As you said, a billion in downstream here or there. 10% of the dividend is less than a billion. How does that inform your take on the overall payout? Secondly, if I may, has the arbitration outcome between Exxon and Hess changed anything in the way you are thinking about rights of first refusals in contracts? Thank you. You say, "Each question is easy." No, because I think clearly, I would say. By the way, I do not like generally too much the right of first refusal or right of preemption because generally, when you give that in a contract, you lower the value of the assets because, of course, it is more complex to monetize an asset when there is this type of right of preemption or right of first refusal. Right of first refusal, by the way, for me, has never been clear. Right of preemption, I understand what they have to do. Right of first refusal, you are always in the debate. You are asking for something, but what is the right to say no? I mean, it is always a source of confusion. I think the outcome is good for the industry because this type of clause exists in many JOAs. They are standard. AIPN clause. It would have been quite a problem if suddenly we had to review all these clauses in allJ OAs. I am comfortable with the outcome. I do not have all the details, to be honest, of the clause itself, but that is for me the way I am thinking. I prefer, honestly, right of preemption if I have to accept an error. Always a little difficult to manage. On the FPX, no, I think, I mean, I am working on the control of. Jean-Pierre. There is no real impact on 2025 because, in fact, 2025. First, we make quarterly dividends. The advantage is that most of the dividends at the beginning of the year were even lower. I think one of them was lower than EUR 1.06. On the average of the year, there will be a very limited impact, maybe $200 million or something like that. It is not sizable. There is an impact. Your question is more relevant, and that is part of when I say the macro environment for the board. There is also this question of USD/EUR exchange rate. We design, I would say, at $17 when we say, in fact, the return to shareholder, you could translate it, but $16 billion. It was eight of dividends plus eight of buyback. $16 at $17, we are considering that it was a high return, but the return we could support. Of course, if we engage and we have not yet enough, I would say, background on the dollar/euro exchange rate, but if we consider the macro is going from 1.1 to 1.2, then the $16 billion could be done in another way. By the way, the board will think about it. If we have to spend 10% more on the dividend in 2026, then we will have to adapt. Keep in mind that it is a $16 billion in that case. It is too uncertain today. Again, I have seen the dollar/euro rate moving down to 1.06 at the beginning of the year, and today it is 1.16. Before we overreact, we are waiting to see what will be done, and we'll have more clarity with quarter to come. Yes, it will be taken into account. If the board considers that we are entering into a more systemic, I would say, 1.2 euro/dollar rate, then $16 billion could be done in another way, knowing that the dividend is always a priority for the board. Really appreciate that. Thank you, Patrick. The next question is from Matt Lofting, JP Morgan. Please go ahead. Thanks for taking the question. I wanted to just come back on the earlier comments on gearing and the balance sheet. If I understood right, I think you were saying that 12%-13% gearing year-end at $70 from February is now more in the range of 14%-15%. Sounded like downstream cash flow at around $1 billion is a part of that. I guess the margin assumptions, 35% looks okay versus where we sit today. Could you just add a bit more color around sort of where the delta is there on gearing and perhaps within the downstream piece, the sources of those moving parts, but perhaps more through asset performance than the margin? Thank you. Yeah. Good match, no, but I've been clear. Honestly, there is a miss on the first half, on the downstream part, and partly it's leading to the performance in particular of two assets that I mentioned in the second quarter. The bad performance of, I would say, Portafer and Donges costed us almost $200 million. There are two other elements in the downstream today. One is the biofuels market in Europe. There is another supply today in Europe. On the biofuel market, the famous SAF market today, Europe and the airline companies are so afraid there is a miss, but Europe is importing from all over the planet, and it has crushed the margin. There is little difference today between the biodiesel and the diesel margin. It has spread again. That is a low signal. Then petrochemicals. Honestly, on the polymer side, we did not comment that too much, but there are several quarters where we suffer from it, in fact. It is not only Europe, it is also Korea. In fact, today, you have and we have to think about it. There was a lot of capacities put on stream in the U.S., plenty of crackers, not because of the domestic market, but for export markets, exporting to South America or to China. In the meantime, Chinese have built a lot of petrochemical capacities, which, by the way, are supplied by NGLs coming from the U.S. It is a little funny, all that. This created, in fact, the Chinese have followed a policy of almost self-supplying in petrochemicals. They have tried to secure. They are obsessed by this idea of security, of economic sovereignty, economic security. Today, in fact, when you look, even the Chinese are complaining, by the way, because most of their petrochemicals are on naphtha, and they are complaining. I met the chairman of Sinopec. I told him, "Yes, but you are a little" "Yes, you are." You have a lot of polymers. U.S., Middle East, China. Today, this, in a global macro, which is not so good. You have a global slowdown. Industrial activity in China is not as strong as it was before. This is clearly on polymers. There is an impact. I am not surprised to see today, by the way, it is good news, but we have just announced we shut down one of our crackers in Anvers. Other crackers have been shut down, in fact, last year in France. Crackers shutting down. Of course, these industrial tools in Europe begin to face the other capacities that we have. We are obliged now to streamline. It will take time when we enter into a low cycle because, again, you have to take strong decisions to shut down a plant. That is the point. That's also why today we had, I would say, first quarter, first half of the year, we had a miss of around $400 million globally, which I think we can reverse in the second half. Not on the petrochemicals, but my refining margins, as I said, are better. Diesel, driving season. So $6 billion by there. The next question is from Lucas Hermann, BNP. Please go ahead. Yeah, thanks very much. Two, if I might. One was just a follow-on. Patrick, just going back to Mozambique, you talked about trying to ensure alignment between yourself and the government. I wonder whether you can make any comments on where the misalignment lies. Secondly, staying with chemicals. Sorry, it's an asset-specific question or a business-specific question, but Hutchison, just wondered how that asset has been performing and how your, and to what extent you feel that that business continues to lie easily within TotalEnergies' portfolio, given the way that you've been pushing and directing the business. Thanks very much. No, Mozambique, I think I made comments. Please do not misunderstand it negatively, what I said. I made a positive comment, which is to start up a lot, to restart a project, we need a strong alignment, and we are working on a strong alignment. Do not try to interpret my words. It is just that we are working on it. We speak about large projects, $20 billion. We need to be sure. Again, we have been obliged to stop, to restart. I need to have all the strong alignment between parties, security, everything. I would say it is important. We are working on it. Again, summer, I said summer, so summer ends September 19. Give me time. Chemicals. No, I mean, again, I think in the chemical business, we have some strong assets, which I would say are the ones which are fundamentally on cheap feedstock. Cheap feedstock. The ones which are historically on naphtha, which are not so competitive. Most of the European assets are on naphtha, and you have the domestic market in Europe is not growing for polymers. It is more the global, there is no big growth in Europe, and that is the point. By the way, should we stay within TTE portfolio? There is an integration between refineries and crackers, which works. It works if we have an integrated platform. Why did we start to decide to shut down one cracker in Anvers? It was not integrated at all in our portfolio. We had a cracker, and all the ethylene was, in fact, sold to ExxonMobil, which was making polymers. ExxonMobil decided to shut down their own polymer plant. No more integration. I will not keep alive and running a cracker with ethylene with no outcome. Integration is key. It is another demonstration. It is screw on the chain. If we have the, as long as we have some integration, it works, then it is better to make, again, to produce these types of polymers in Saudi Arabia or in Qatar with cheap feedstock than with naphtha, which is more expensive in Europe. By the way, maybe you have an idea to whom I could divest, but I am afraid that you never make a good business when you sell at a low cycle. You prefer to buy at a low cycle. I will not buy assets in chemicals. Just do it. Do not be afraid. Do not be afraid. I look at it. There is no message. I am not there. No, I think it is part of the, as long as they are integrated to the refineries and strong refineries, it is okay. Again, when we have weaker assets, we take a decision. On Antwerp, it has been possible, and we accelerated the decision, by the way, because at the same time, the refineries are doing well. Translating some people, we have a lot of more and more people going in pensions. In pensions in Anvers because of retirement age. We moved people from the cracker to refineries. It was a good way to manage this shutdown. That's where we are. Sorry, Patrick. The question was more on Hutchison itself. Oh, but Hutchison. You should ask your question clearly. But Hutchison is not a chemical business. It's a manufacturing business. And by the way, Hutchison's performance is very good. Yeah, on the other side of it was to what extent? And it still fits very comfortably within your portfolio. Oh, I don't spend much time. I can't tell you. One hour per quarter. Okay. For a good business, that's fine. If you find a good buyer, no, no, no joke. Honestly, it's a company which works well. There is no problem. I have more interesting, I would say, M&A to do for the company, for the future portfolio of the company in oil and gas or in integrated power, not to spend too much time and to have problem issues or worries about this type of it works well, so I'm comfortable. That's where we are. I have better ideas for the future of TotalEnergies and no problem with Hutchison being in our portfolio. Thank you. The next question is from Kim Fustier, HSBC. Please go ahead. Hi, good afternoon, and thank you for taking my questions. I had two, please, on the upstream. The first one is on your portfolio activity. You've been very active in recent months, and you've done a lot of deals to replenish your upstream and energy portfolio for the post-2030 timeframe. I'm thinking of deals like Algeria, U.S. Gulf of Mexico, Malaysia. I just wondered if that signaled a change in your view fundamentally on the prospect or the timing of peak oil demand. Are you effectively trying to extend your production plateau to sort of match the shape of global oil demand? My second question is on disposals. Some of the upstream disposals that you've announced weren't necessarily expected, thinking of Bonga or Argentino Shale. Are these opportunistic deals whereby you're sort of open to incoming bids, or are disposals increasingly an important part of your cash flow cycle as a way of maybe generating cash to support your balance sheet? Thanks. Okay. Very interesting question, Kim, both of them. Okay. In an oil and gas company and an energy company, and oil and gas in particular, you have a natural decline. One of the objectives of the management is to think long-term and to not, it's not because we have a very large portfolio of opportunities between today and 2030, but life does not end in 2030. We must continue. I think for the time being, it's not a matter of history, peak oil, peak blah, blah. I do not know. Peak oil or peak demand or peak of price or duty is clear. We have one way to look to opportunities. If it is first quarter, second quarter, which means less than $20 per barrel CapEx plus OpEx, low breakeven, less than $30 per barrel, I am happy to continue to provide this type of opportunities to the portfolio of TotalEnergies for the future because these opportunities will be profitable even during the 2030 plus. Even if you have a beginning of a decline of oil demand, it is possible. I do not say no. The protection that I bring to our shareholders is we are first, second quarter assets, and that means that we can continue to allocate capital to these assets because they will make money even if there is a decline of oil price. Decline of demand, by the way, decline of demand does not mean necessarily decline of oil price. Because if everybody is anticipating a decline of demand, you have less projects. It is good to have some projects just to be there and to capture these good opportunities. Yes, we continue to work. By the way, most of what we have done, but it is not so much oil in what we have announced. It is more gas, in particular in Malaysia. The Malaysia story, we will come back on it. Some of you were probably surprised when we acquired SapuraOMV last year. Why do they build this position? Now you have this follow-up. We are very happy about the last deal we have done with Petronas, which is 12 blocks, not only exploration, because in the 12 blocks, there is a DRO, a Discovered Resource Opportunity, of 3-4 TcF, which we will develop. It is giving, I can tell you, a good additional value to the fact that we have acquired this position. These types of things are very logic and gas. Gas in Asia, honestly, there is a bigger demand. It is good to continue. Divestments, no, I think it is very consistent, the last divestments. We told you we have a very broad portfolio. Some people even think we have too many opportunities. I prefer to have a lot of opportunities and then to arbitrate. Of course, look, these two opportunities, which were non-operated by us with minor share. Why allocating capital to even if the projects, I do not consider the project is not good. I just say we prefer to allocate capital to larger, to Suriname and to Block 53, to expand Suriname, than putting some billions or hundreds of million dollars to finance a 12.5% share in Bonga. It makes very sense. and Gato do Mato is the same. We have a huge portfolio in Brazil, Sepa-2, Atapu-2, all that, Lapa extension. It is a matter of managing and to keep the discipline, I think, on the CapEx. If I keep everything, I prefer to arbitrate the non-operated assets, which, by the way, in both cases, have a higher cost than $20 per barrel. It is not completely fitting with our metrics, but it is quite logic to divest them and to find a buyer, which in both cases, by the way, is the operator. It makes a lot of sense. I think it is part of what we have to do for keeping care of the allocation of capital for our shareholders. The next question is from Alastair Syme, Citi. Please go ahead. Hi, Patrick. Just one question on biofuels. By observation, maybe I'm wrong, but European countries seem to be quite slow to legislate on Red III. Do you sense in your discussions that there's any political debate about the cost of biofuels, given that renewable diesel and SAF are still three times the cost of the fuels they're meant to be replacing? On the biofuel, no, I see most debate about what is around hydrogen and all these types of molecules. On biofuels, I do not think there is a—in fact, the biofuel business is more hit today by different elements, in particular on the sustainable aviation fuels. There was a new regulation which was issued in summer 2024, which allowed to make co-processing in our refineries. We co-process some used cook oil or some HVO that we produce in biorefineries to make sustainable aviation fuels. Of course, the cost when you co-process in an existing flow, the marginal cost is almost nil, I would say. That clearly has changed some. I think some countries begin to think, what is the share we want to allocate to that to compare to, I would say, the pure biofuels products? Of course, it is very important for companies like us when we invest in biorefineries. I am also a co-processor, so I am both. We need some more clarity because it is possible today because, again, what happens in this debate and airline companies are very vocal. Everybody, like always in energy, they want the cheapest possible product. They want the low-carbon product, but the cheapest one. If it is cheaper to make it by co-processing, by making as a transformation in a biorefinery, they will favor the first line. For us, it is clearly for me, so that is true. In our plan, we have done La Mede, we have done Grandpuits. We are thinking to a third one. For the timing, we have postponed it because we said to the team, look, there is maybe a change in this market. Let us put, because honestly, to make more co-processing within TotalEnergies, it requires a few tens of millions. I mean, we are not speaking about hundreds. It is tens of millions, less than $50 million. We could produce more. This is what we will do. This is not—this is slow to regulate. There are new elements of regulation. The lesson is that this biofuel market is a regulated market. These molecules are regulated, heavily regulated. All that, and it is a little true, what you said, Red III is a European directive, but then each country begins to make its mix. We have to navigate for that and not to anticipate too much on what could be the regulations. Then we could make some misallocation of CapEx. This is where we are. The biofuels, I see, I think we will have—I mean, we need to integrate these. There are some technological disruptions, in fact, which is what happened. Because when I was asking to my refiners, why do not we co-process five years ago, they were speaking about corrosion difficulties. In fact, we make some tests. There is no nutrient corrosion, etc. Things are moving. Things are moving in all these new low-carbon fuels. Great. Thank you. The next question is from Henri Patricot, UBS. Please go ahead. Yes, I want to thank you for the great touch. One topic left, which is Namibia. I was hoping you could give us an update on Venus, the latest online, and also whether the project could change if you get involved in the blocks next door with the Mopane being discovered. Thank you. Next door is a little far away. Yeah, Namibia. I know I told you that I visited—I don't know. I mentioned that I visited Namibia. I met the new authorities. It's a new government and very willing to, of course, develop the oil industry. We are the first one there with a project. We have, of course, to tackle some issues with them. I received a letter asking us to engage in the discussion. I think there has been a team set on the Namibian side, reporting directly to the president of Namibia. It was her decision. On our side, we are ready. I think it's a matter of—we are working. I think we need to—it's a little like Mozambique. You have a new country to oil industry. It's important to ensure the alignment, the good understanding. I don't want to have a dispute. We're investing and then discovering a problem because the Namibian authorities would have the feeling that we are not—that they did not understand all the projects. I want everybody to—it's better to take time at the beginning, even if, of course, we are ready. They are very motivated to—they would like the oil to be produced before the end of 2029. That means that we should take decisions this year before the end of 2025 if we want to meet the target. This is what we explained to them. We'll do it. We're working with them. I cannot tell you more. On the opportunities next door, again, it's not really next door. It's a little far away. We'll see. I mean, we'll see what will happen. We'll see what will happen in this business. I'll let the company work on it. Okay. What we do, by the way, on our side, Namibia, for me, it's also the next news will be South Africa because we have also some wells to be drilled. We have some attractive license just across the border. We have, I think, two or three prospects. We are working in South Africa as a process to get all the authorization. It's quite a little long, but we hope to begin to drill South Africa targets in 2026, from 2026. That's where that's also Namibia is also linked to this one. The next question is from Paul Cheng, Scotiabank. Please go ahead. Thank you. Hi, Patrick. Good morning or good afternoon. Two questions. First. In the U.S., we have a president that loves to trade it maybe in the middle of the night and subsequently that oftentimes makes a significant impact on the market condition. I see in any shape or form that impact the way how you manage your trading operation because a lot of times that the trade is going to insert an element of unpredictability. You can't really predict what he may or may not do at a particular moment. So how you guys will be impacted or that you say, "Okay, this is just part of normal operations, so I'm not going to impact by that." The second question. Is you've been reducing your European refining and chemical operation. For an obvious reason. In the long haul, do you foresee that you may totally exit from refining and chemical in Europe or that you think you ultimately are still going to have some position you just need to strengthen it? Just how you view on those assets in the long haul. Position in your portfolio? Thank you. Okay. I think the first one I commented is already. It's true that traders have to be. Do not like too much to see. I would say they fundamentally try to trade around fundamentals to take position about analyzing the supply and demand and the different regions and the different optimizing logistics and all that. Of course, they don't like too much to see this element of uncertainty with markets reacting very quickly to a tweet, makes their position quite stranging. Yes, like Jean-Pierre is just telling me a nice sentence. Volatility around tweets is not tradable. This is what, by the way, what's true. Volatility around tweets is not tradable. That's what our traders told us. They told us, "Don't expect us to make maybe they make very good results about the old business, old guys. They were completely aligned with our expectations." They told us, "Don't expect sometime we could expect more, but. We can be reversed." We are obliged to be more short-term, I would say. The consequence of that is that if you want to play three, six months, you could be suddenly your position, which seems to be good, could become not the right direction. That's the difficulty of it. Having said that, again. They have our trust and our support, and they are, I would say. They are aware, and I trust them. They know what they can do and what is tradable and not. Honestly, again, the old trading of TotalEnergies has gone as expected. There is no problem. On refining, okay, look. It depends what will happen. There are two different positions, but it's linked. If Europe really goes to no more gasoline, EV vehicles, light vehicles in Europe, we don't need to have refineries to produce gasoline. I mean, I'm just. I'm joking. The question, it's not 2035. 2035 will be stop commercializing if they really take on this position. By 2050, I believe there should not be a lot of gasoline cars in Europe. I could think it will be a reality. Of course, we have to think to this perspective. It's still a long way, but we have to think to that. We have some very strong assets in Europe. I would say the stronger ones are well-known. It's Antwerp in particular. It's a very strong asset, integration. The first quarter assets will survive. The third quarter, we need to think to their future. Their future might be to become bio refineries like we've done for two of them. Or their future for a cracker, if we can do it, shutting down the cracker in Antwerp because in Antwerp, we are able to we have taken the decision because we didn't see of to maintain an isolated cracker in this context. I mean. Will we keep the position? I think this position is a dynamic position which will evolve according to the market, which is declining. Strengthen it. Strengthening Antwerp maybe because it could be one of the last refineries in Europe. We cannot spend too much money on this one. That's one difficulty, is that refineries, if you want to maintain, I mean, good availability of refinery with high level of safety, which for us is fundamental, requires to have a maintenance CapEx, which is quite burning some cash. All that is better to have a—what we monitor there, I will tell you, is what is a global cash position, net cash position on refining in Europe. Of course, if we begin to have a net cash negative, then we'll have to be tougher on these ones. We know the issue. We are in Europe. It's part as well. That's why it's not easy. If you look to the narrative of it around energy in Europe, it's more and more about energy security, energy security. Refineries are part of the energy security. You've seen the debate in California recently where California people are very afraid not to have enough refineries. It's quite funny because they have made regulations to shut down all of them. The U.K. as well, you've seen that two refineries have been announced to be shut down. That's where, by the way, governments will be an interesting debate with them. Because on one side, they give us a signal that they don't need gasoline by a certain distance. On the other side, some people will say, "Yes, but we need these tools just in case, just in case in the future." I think we have, so our objective, it's at the end of the day to reinforce the first quarter assets and the others to find a respectful evolution for people. Thank you. The next question is from Jean-Luc Romain at CIC Market Solutions. Please go ahead. Thank you for taking my questions. It relates to the asset sales you plan in the second half in integrated power. Do you believe it will put back the rotation of this division back within your 10%-12% target? That's the first question. The second is about VSB. Out of the portfolio of VSB, how much did it went into the under construction tables and how much went into the under development project out of about, I think, 18 MW of projects that were mentioned in the press release of the acquisition. Okay. The first one. No, I mean, Jean-Luc, very reasonable. We announced that we want to be at 12% by 2028, 2030. We will not reach 12% because of the divestment of the single-arm. It takes more time. We are still in a growing mode. Our capital employed are still growing, which is normal. I accept it. Today, we are more in the 9%-10% range this whole year. The 12% will require, at a certain point, to have enough capacity to stabilize all that and to continue to develop the integration, which is done. I will be cautious this year. We are still, I would say, targeting the 10%, 9%-10%. That is what we want. This is where it will go. I am optimistic of that. I do not expect 12% in 2025. It is not on the roadmap for my integrated power teams. They have a lot of challenges in front of them. I do not want to add on this one. That one, maybe I disappoint, but it is more pragmatic. On VSB, I am looking to my friends to give me a so. No. What is installed? There was 500 MW installed, but the question you are asking is, what is under construction and what is more in development? I know that we have approved recently three projects from VSB. In the executive committee, they came. In less than two months. In less than two months, they came to us to approve three projects. I think I do not have the answer to your question, Jean-Luc, sorry, but I think Renaud and his team will come back to you. I mean, I have seen the figure, but I do not want to make a mistake there to give you a wrong figure. I will come back to you. Again, just to demonstrate that we have approved around three projects recently, which were representing globally, I think, something like 600-700 MW. There is more to come. What we plan to develop, yeah, but I am not sure. In the long term, but I do not know what it is. Long-term plan, that is? We could see something like, no, we will come back to you. I think it is around 3 gigawatts, but I will come back to you. I prefer not to give you wrong information on this one. Thank you very much. Very clear. The last question is from Jason Gabelman, TD Cowen. Please go ahead. Yeah, hey. Thanks for taking my questions. I wanted to ask on integrated power in the U.S. specifically. Given some of the changes to the tax credits in the recent tax regulation that was passed, does that change your view on the pace of development in integrated power in the U.S., the returns, and the ability to farm down assets there? I will tell you, in fact. What I observed on the farm-down in the country is because there is a fear of scarcity of this type of assets. Financial investors, which are in fact buying this farm-down, are even more aggressive on the valuation. What is more, piloting the farm-down is more the interest rate, to be honest. Today, the scarcity of assets, or the risk of scarcity, there is some appetite. There is no doubt. As I said, we are farming down 1.5 gigawatts, and we receive very good offers in line with our expectations. Do not misinterpret it, what has been the big, beautiful build for renewables. In fact, when you look at the end of the process, tax credit, either PTC or ITC, that did not really change, providing that the project will be put into construction before mid-2026 or 2027, mid-2026, I think. We are working on that. What we could say, harboring. Of course, the condition of safe harboring is important. When we look to our portfolio of projects, for us, when we look to what we were planning to develop between today and 2029, 2030, there is not much impact on all that if we can safe harbor, of course, correctly and according to the rules. I think we will come back to you on this one as well, end of September. The ITC and PTC quantum did not change, in fact. The capacity to, I would say, how do we say that, migrate between the market for ITC, PTCs continues to remain. What has been the tax partnership and all that remain. Most of it is just a matter that it will elapse in time. With what has been voted in the Senate, it is possible to use that. It could have some impact. There is one part which is more impacting, in fact, for me, these businesses, is more the tariff. As I said before, because the tariff, you do not have today in the U.S. enough manufacturing capacity to make all the projects. This tariff, if it depends, and as the tariffs are not the same for all the countries, we are, I would say, in a shadow today. We do not know. Of course, it could have an impact on us on diversifying our supply chains, finding new countries. I know that we stopped one project in April with a provider coming from China, but we managed to replace it with a provider from Vietnam. By the way, this Vietnamese company wants to build a manufacturing plant in the U.S. You will see some ways to, I mean, this dynamic will come. Finally, building a solar plant, manufacturing plant, a manufacturing plant for solar is not so complex. In fact, but we see some trends. Again. I do not tell you there will not be a form of slowdown, but it will not be dramatic. Again, for us, it is value over volume. Let me be clear. I have been very clear with my teams. Okay, you want to grow, but we will grow at a pace which will be allowed by the global framework. We need to digest all this information. The last news I have got now that the bill has been enacted is more positive than what we thought. There is one segment which has completely, we put into, I would say, a sleeping mode. It is offshore wind. This is completely sleeping now. Sleeping, that means nobody is taking. We have reduced at a minimum any cost on this one. Integrated power is also gas fiber plant on this one. I can tell you, we could make a lot of money by farming down part of a free 1.5 gigawatt we have acquired two years ago in Texas. We could find. At the end, we want electrons. We can remove from the totally scheme. There are ways to use these types of assets to get some money back. There are good things as well in what happens in the U.S. on the electricity side, including gas to power, which is, of course, at the core as well of our business model. It is not only renewables. Our business model, in particular in the U.S., is gas to power plus renewable, but gas to power are very important. Yep. Got it. My follow-up, it's probably fitting to end on a CapEx question given all the focus on that. It seems like to hit the organic CapEx target, CapEx needs to slow by almost $1 billion from 2Q levels. Can you just give us some sense about where the activity is slowing down? Also, if Mozambique LNG, if that moves forward, is that already in the CapEx budget, or would that be incremental? If Mozambique LNG is moving forward, it will be externally financed. The impact on the CapEx budget is quite limited. Got it. Or just more broadly on, yeah. No, thank you. Sorry, Jason, but I cannot give you, I mean, I do not have all the details. No, this one. No, but I mean, we know where we are going. We know why. For example, I will tell you, this pipeline in Uganda, we put in place a project financing in the middle of the second quarter. It has a positive impact on the CapEx on the second part of the year. The run rate of spending was higher at the beginning of the year than the second half. This is very pragmatic, this one. When I told you that we will stick on the $17 billion-$17.5 billion, I repeat it, you can believe me. Know what we have behind. Okay. Thank you. Thank you. I think we come to the end of the call, no? Yes. Do we have another one? No? It's okay? Thank you to all of you for all these debates and questions. Again, I think the keyword of TotalEnergies, I know it's a little boring, but it's consistency. It's good. It's not so boring becoming consistent. Consistent in the strategy. Again, keeping the return to shareholder on the high side. I think it's good news for our shareholders. We are in a cyclical, we are in a commodity business. We don't control the markets. Today, there is volatility from supply and demand side, but also from geopolitics. It could be on one side, and we go the other way. What I'm sure is that we manage, we have the flexibility, the agility in the company to manage all this high-rate volatility, and we are growing again. As always, the growth is delivering some additional cash flows, which is very important for the board. The board already monitors as well. Do you deliver what you said in terms of growth of productions on both sides, in integrated power and in oil and gas? I would be happy to meet all of you again in New York on September 29. I know it's an annual one, so we will give you even more certainty about our business plans towards 2030. I hope, I am happy to advance to and enjoy to meet you there with all my executive committee. Thank you. Ladies and gentlemen, this concludes the conference call. Thank you for your participation. You may now disconnect.