Good morning, everyone. We are delighted to welcome you to TotalEnergies Strategy and Outlook Meeting 2024. This is, of course, a special event this year, as we are still celebrating the hundred years of TotalEnergies. So today, of course, we'll be talking about the strategic outlook for the company, but we can also take this opportunity to reflect on the long and successful history of the company, which are making that we are here today in New York City, with a nice view on Central Park. You can follow us live on our website, totalenergies.com. The program today will start with the strategy and outlook presentation, which should last around one hour fifteen, one hour, one hour thirty, and then we'll be moving to a Q&A session, where you will be able to ask all the questions you want. We have a dedicated line which is open for the people who could not attend the event and we'll take from time to time some questions, online. We should be done around 12:00 P.M., and we will then go for the lunch. But to start the meeting, and, as it is a ritual at TotalEnergies, I invite on stage Vincent Stoquart, who is our new President, Refining and Chemicals, for a sequence on safety. Vincent? Thank you, Renaud. Good morning, everyone. Happy to be with you today and to share this safety moment. So, go to the appropriate slide. So you probably know that TotalEnergies celebrates its one hundredth anniversary this year, so this comes with one hundred years of experience to improve continuously safety, which is our core value. And one key element of that is what we call the return on experience process and what we call the REX. REX has proven its efficiency in order to share through the whole company this experience and to avoid accidents. So just wanted to mention that because today we push that forward, thanks to our Digital Factory and to artificial intelligence, and to take a very concrete example, in our industrial facilities, we need to have a work permitting in order to start our works. And we have deployed already today an application which helps the operational teams to instruct this working permit, thanks to data processing of all this material, massive material of return of experience, and then to suggest the appropriate safety measures, thanks to artificial intelligence. So it's a concrete, real example of what we do in safety with these new tools. I wanted also to come back on this continuous improvement with a few data. So the chart on the left, it's the usual Total Recordable Injuries divided by million man-hours. What you can see there is that over the last 10 years, we have divided by two this important KPI, and today, I think we can say that we are in the best-in-class peer group. And the same for the so-called LOPC. So LOPC is the quantity of events of loss of containment in the process, and there you can see the same trend, so minus 70% of these kind of events over the last decade. And we have, of course, action plans in order to pursue that and to diminish even further. So thank you, and I will hand the floor to Patrick Pouyanné. Good morning, everybody. Happy to see you today in New York or live on internet. First, before I enter into the discussion, just to... You just have the chance to be introduced to Vincent by himself. So Vincent is our new President for Refining and Chemicals. These are the people around the table. This table is only with men, so it's not too much diverse, but Helle will be live today to speak about Asia from Tokyo. So you will have Helle speaking, and you have Namita, our One Tech President in the room, as well as, by the way, Aurélie Alemany, which is our new President, Strategy and Sustainability. You know this face. So Bernard Pinatel is president for Downstream and Marketing and Services, Nicolas, President, E&P, Jean-Pierre, our CFO, and Stéphane, President, Gas, Renewables, and Power. And, they will have the opportunity to share this presentation with myself. So just to set the scene, I will say today, what do we want to, if I try to summarize what we intend to present you, we have a strategic consistency within TotalEnergies, so don't expect any change today from this perspective. The transition strategy has been established a few years ago. We are progressing on it year after year. It's a balanced strategy between the two pillars. I will come back on it. I like what you hear today, and I will borrow to one of you the title. I read a nice paper called The De-risking Show. So we will have a de-risking show today. De-risking, I would say, on the growth part, because it's important. We have a growth profile of energy, and I will come back on it, including in oil and gas. We will be able to not only de-risk, but to upgrade and to extend it, and also de-risking in terms of resilience of our business model. You know our low break-even, you know about our low-cost operatorship. We'll speak about LNG and our portfolio of can we de-risk the LNG portfolio, and of course, for the benefit of all our investors. So we call this presentation More Energy, Less Emissions, Growing Free Cash Flow. The free cash flow, and generally, we spoke about cash flow, but at the end, what is of interest for you is your free cash flow, which could feed your higher returns in the future. So I would say this is, globally speaking, what the message today be speaking about the strategy consistency, speaking about the growth we have embedded into our portfolio, and speaking about the resilience as well, and all my colleagues will come back on each of these pillar. So just before to engage in the strategy, the energy markets. The energy markets are. This presentation is coming at a volatile time, to say the least. But first, there are some fundamentals, which I just want to remind you about the, I would say, the demand for energy. It's not in this transition, I would say, energy transition. That's not the best, the easiest part of the equation to guess. But what we are convinced, and which explain why we have this strategy with two pillars, is that we need both oil and gas in order to meet the demand and low carbon. On this chart, we have an assumption, which is that the energy demand continue to grow around 1.5% per year. The population grows by 0.8-0.9%, and you have as well, in emerging countries, population which are reaching, better living standards. And despite some energy efficiency gains, you have a continuous growth on energy demand that the fundamental. On this chart, we took a bold assumption that the objective of the COP twenty-eight of multiplying renewables by three could be met, which is not so obvious, to be honest. But what happens if it was met? Of course, the renewable part will grow quite dramatically in meeting the demand. But we wanted to illustrate that because there is a 4% decline on the natural decline on the oil production, on the oil, and despite all the efforts to manage this decline by many operators, at the end, if we don't launch new greenfield projects, there will be a supply gap. We put minimum supply gap, because if the objective of COP twenty-eight multiplied by three is not reached, the supply gap could be larger. So we need to continue to invest in oil. Of course, the gas, we put an assumption, which is, most of the gas demand is driving by the LNG capacity growth, and we will come back on it. And one elephant in the room being the coal, because in this chart, there is a little decrease of the coal by 10% before decade. As, Michele, in his Carbonomics studies are explaining to the planet, but people should read what Michele has written. If we want to be one point five degree, we should get rid of coal by the end of this decade. We are far from that, in fact, so even we have the assumption is a little optimistic, but, I think if really COP 28, the multi renewable objectives is multiplies threefold, then there will be some impact on it. So that's the landscape, and that's explain our strategy, which is to bet on two pillars: the oil and gas, the energy of today, and some low carbon energies, in particular electricity and some bioenergy as well, because this is part of what we need to develop to decarbonize this energy world. On the oil side, I would say, the more we look at it, the more we see year after year after, of course, this Covid impact, where maybe people were suddenly thinking that this was the beginning of the decline of oil. The reality is that the oil demand is growing. It's growing a little less than one, let's say, one million barrel of oil per day. We don't see for the time being, a real impact of the penetration of low carbon technologies. We see more impact today in 2024, I would say, of the Chinese slowing economy rather than about the technology's impact. It's more a macroeconomic impact. Our view is that this decade, we should see a continuous liquid demand growing for until 2030, a pace which could diminish because, again, low carbon technologies could engage, and with the risk, in fact, about the supply. But about the supply, and today it's at the core of all the debate, I think, in many, many places. Okay, we observe a non-OPEC supply growth, it's true. But again, ex-shale, U.S. shale, this supply growth is not very sustainable. So you have some few countries, but it's, in fact, it will be more stable or even decline. The ex-shale, the shale, US shale is a source of growth for sure. You have the OPEC policy, which is today again put into question. I think I interpret the Saudi message to their friends of OPEC and OPEC+ that they need to be compliant with the quota, otherwise they could act as they've done in the past. I will see what happens. All that being the supply being in a global framework for constrained investment, because in fact, we invest today less in oil, in CapEx in oil worldwide, but what we are doing in the year 2010, 2050, we should not forget that. And so that, of course, this global framework of constraint investment, if the demand continue to grow even beyond 2030, that will impact the price. And so on our side, I would say, and I understand that maybe today, immediately, on the short term, it could be surprising, but we are more thinking that we are more bullish on the oil price, which explain why we continue to maintain our portfolio. The second market, which of course is very important for us, is the LNG. It is clear that we will face a supply wave of LNG by 2027, 2030. We made the math. I was making the math. It's in 2027, 2028, 2029, you have plus 50 million tons of new capacity per year, which makes more or less 10% of the market additional capacity. So it's 30%, in fact, when you take a few years, which is not the first time that we face such a situation. In 2010, 2011, we faced already a situation where suddenly we impacted the market by an additional 30% of new capacities. And in 2016, 2018, there was also a wave of new capacity. By the way, it's an industry, the LNG, which is completed by wave because it's massive CapEx, and in fact, people are all, you know, the ships, you know, me too, me toos, we follow the others. You know, when the price is good, we invest, and then suddenly you have the wave. The good news with the wave is that in between, there is no new capacity, so in between, you capture, I would say, because the demand continue to be there for gas, so it's a good market like it is today. I mean, people complain about the gas price, but I'm happy when I see $12 per million BTU on the European gas price. I mean, it's not the 20 or the 30, which was completely exceptional, but we cannot complain about 12 or even 13, if it's more, dollars per million BTU in Europe, compared to what we could have experienced, $5, $6 five years ago. So we should never forget that. And then, so you have periods where capacity like 2024, 2025. I know there is a debate on 2026, but honestly, when you see the announcement of our colleagues, I see more delays than really acceleration on any of these LNG plants. And so, we think that 2026 will remain. It's only 25 billion tons, which are expected of new capacity if they are on time. So it's 2027, 2028, 2029. The lesson as well of the past is that each time you have a new capacity, a new wave of new capacity of LNG, of course, the price are softening, and it's a market which is quite sensitive to the price, and so it fosters the demand. It was exactly happened in 2010, 2011. It's again, what happened after the wave of 2016, 2018. I think, by the way, it will be good for this market because what with the prices we experienced in 2020 to 2023, we see some customers begin to be afraid by this hike of gas, this huge volatility. We will enter into that market, and we have to face it, and we will explain you how Total is preparing itself, TotalEnergies, sorry, is we are preparing ourselves to this capacity wave, as we are part of it. We cannot complain about it. It's part of the strategy and the way we, in fact, wants to manage it. Just a last word, when we say that we anticipate an average growing demand of 5-6%, when you take the history of this market, it was 5% for decades. In fact, the demand is quite largely led by the supply. It's a question of catching up and then to the next wave. The last market of interest for us is of power, the power demand. So we don't speak today about hydrogen, but about AI, data centers, cryptocurrencies, people are... I just want to remind everybody that, yes, it's a growing market, but it's only 2% of the electricity demand today, these data centers. All right? It's not big. So even if you double it or if you triple it, you go to 2%-6%. So yes, it is a market. It's market, in particular, in some key countries, and for us, it's coming. When you look data centers in the U.S., where you need to have a, I would say, base load, clean power for these, tech companies, this is what they are asking us. It's an interesting market, and Stéphane will come back on it. But to say, if I can read, that suddenly it could be too much demand for that, I think we can find a way to... It will be included in the global power demand growth, which is an average 2.5% per year. This year, it's 4%. Next year, it will be 4% again. There are a few key countries there again, and we will see China as a huge growth, and India as well, are the two countries who are leading the global demand for energy, for electricity. The good news with the data centers, AI, cryptocurrencies, is that there is also a growing demand in a country like the US, which is a good market for developing our business. After the landscape and the energy markets, I move on to the way we execute our transition strategy. There are two pillars, you know it. The Oil and Gas, Integrated Power. They are not exactly on the same size. By 2030, it should be 80% on one side and nearly 20% for the Integrated Power. On oil and gas, we have the benefit of the depth of our upstream portfolio. We'll come back on it. Today we will firm up. We are high-grading our guidance for our oil and gas growth to 3%, from 2% to 3% to around 3%. Not only by 2030 we extend it, but you will see that even from 2025. We have also a large, deep LNG portfolio, and we will explain to you why we think it's resilient to the cycle, of course. And at the end, all this business, and that's part of the presentation, will generate additional cash flow, more free cash flow. More than $7 billion of free cash flow will be generated between today and 2030. Integrated power, we'll come back today on the model. More and more we speak about integrated model. Clean firm power for customers requires a combination of gas, batteries, renewables. Stefan will explain you why we think that we should reach at least 12%, and that we will reach at least 12% return on capital employed, and being positive free cash flow by 2028. This, I will insist, because I have always a question about, why do you think this combination could be good for our shareholders? That today, the, we benefit from being the, having offering in, among oil and gas majors, the highest return on capital employed. That's a calculation on the 12th by end of June 2024, it was the same, so last two years. We will offer for the future the highest energy production growth, energy covering all type of energies, not only oil and gas, but also electricity and bioenergy. Coming on oil and gas, because growth, but true that we since last year in September, we worked hard within TotalEnergies to de-risk the profile that we propose you to of a growth. Not only we de-risk, but we upgraded it, and we also today can extend it to 2030. Guidance we gave is an increase of 3% per year as an average. We benefit, we have worked hard to sanction many projects in 2024, which will fit with mid-term growth, Kaminho in Angola, Sépia-2 and Atapu-2 in Brazil. And yesterday, I was myself with Nicolas in Suriname for the sanction of the new GranMorgu 220,000-barrel-per-day oil project in Suriname. And we also sanction some LNG projects. Marsa LNG, which was not in our profile last year, it's not a big project, but as we have 80% of it, 1 million ton, 1.2 million ton, it's an interesting project in Oman. And we also have worked in order to increase our gas supply to the future LNG Train 7, Nigeria LNG plant, which suffers today of a lack of gas. So it's an opportunity for us to accelerate the production of our gas reserves in Nigeria. But on this slide, I want also to insist on the fact that the growth does not wait for 2028 or 2030. It's starting from next year, because we have started in 2024, and we'll start in 2025. A number of new projects, we started Anchor, we started Fenix this year, Mero-2. Mero-3 will come on stream before year end. We will have Mero-4, the first phase of Ratawi, and in 2026, we'll have Tilenga and also NF from Qatar. So, the growth profile is not only something which will come at the end of the decade, it's starting from 2025, and it will be a reality in 2025 and 2026. And this will be help us, of course, in case of low, I would say, lower prices to have higher revenues, so to face a volatile price if it happens next year. To do that, I want to introduce to you today to give visibility, because we have many questions about how much you spend to do all this growth. So we give visibility on the organic CapEx, and then I will come on the net CapEx. The organic CapEx, when we look at that, it's around $17-18 billion for the next three years. And you will see that we keep the guidance of $16-18 billion, because at the end, the M&A will divest an average of $1-2 billion dollar, as we do every year after year, so there is nothing exceptional, but I think it's important, and you can read it like when in fact, fundamentally, because we have a deep portfolio, we don't need to make large M&A. We have been very selective. We acquired position in Malaysia. We are continuing. You've seen that we announced last week a second acquisition in the US shale gas. It's part of the de-risking of our US LNG position. But we'll continue to pursue some disposal from non-core assets. But on organic cash flow, there is the next three years are full, but there is room if we want to, as we have, if our explorers continue to be successful, to FID new projects between today and the end of the decade. Keep in mind that now that we have de-risk most of the projects, the EPC contracts are secured, so that mitigate project inflation risk. Secondly, we keep, and I will come back on it, the flexibility to respond to changing market conditions. Organic CapEx, the framework for the global capital investment strategy is still the same. It's $16-$18 billion, 2025-2030. Around $5 billion for low carbon energies, $4 billion for integrated power, a little less than $1 billion for low carbon molecules, fundamentally bio energies, and CO2 CCS, and a third on new projects. We confirmed the guidance for full size goals, which would be 14-18, and in fact, we have in our portfolio $2 billion of short term CapEx flexibility that we can activate in case of brutal or sharp decrease of oil price. Sharp meaning lower than $50 per barrel, in my mind. We are comfortable. And why we are comfortable is because the balance sheet is strong. You know, in 2020, we maintain the dividend during the COVID. We can maintain our CapEx program and our return to shareholders because we have a stronger balance sheet, and we can use it if it's needed. A word about the LNG. LNG should be in the title there, but our LNG portfolio. First, I just wanted, because it's new, it's a second question that some investors have. You have taken strong position on LNG. I just want to remind you that first, we are investing in projects which have a low liquefaction cost, top tier in the merit curve. So it's the first answer. Second, in fact, what we do with Stéphane's team, and Stéphane will come back on it, so I will not comment on it in details. And you can see that we have worked quite hard. The teams have worked hard this year in order to sign some medium, long-term contracts, and in fact, mostly indexed on oil. We transform some Henry Hub into oil, which is not a bad deal, in fact, if you think about it. And we try to lower the exposure to, and we want to lower the exposure to the spot price for the reasons I've explained before. So we are working on it. More than four million tons of medium, long-term contracts will be signed this year. And we have also, by the way, one way to manage this Henry Hub is also through upstream gas integration, the position we are building in the Eagle Ford, the step after first and the one we have in the Barnett. Just a framework for integrated power. The more we move in that business, the more we see a huge value of the integration of gas to power, which for an oil and gas company is somewhere quite, I would say, natural. But true that we have to invest in, renewable assets. But if these renewable assets are intermittent, and the value of an intermittent electron, in fact, for a customer is not very high. But if you manage, and Stéphane will come back on it, to sell what we call the clean firm power, and it's possible, thanks to the integration with the gas and the fact that we control also where we are integrated on the upstream gas production, is giving us an advantage in terms of, in terms of fluctuation of the gas price and the impact on the electricity, gas-fired plant, electricity price. So that's something we are, and the same if we want to benefit from renewables, developing some storage capacity, some battery capacity is also important. So that's this combination of renewable and flexible assets, which is a core strategy, and which allow us to take some merchant exposure to capture some upside and also to have to enhance the value we get from customers. So we confirm on this, the two key part, two key metrics, which are the target to produce more than one hundred terawatt hour power generation by twenty thirty, which means more than five hundred thousand barrel per day equivalent, and the return on capital at least at 12% on this business, we being today at 10%, and Stéphane will come back. If I try to summarize what we present, we will present you and my colleagues will give you some details. Our global energy production is growing by 4% per year, a little more, in fact, but 4%, let's keep 4% per year. At the end of the decade, the electricity will nearly be 20%, 20% more, 18%, but it depends on different factors, so nearly 20%. We continue, of course, to be committed to lower our emissions. We are on the way year after year, and all the business plan confirm that the -40% net Scope 1 and 2 decrease will be met by 2030. And also, it's important because it's for me the key marker of our transition strategy. When we look to the average carbon content of our energy cells, we are diminishing year after year, this average carbon content, minus 25%, and we are clearly leaders on this slide. I would say if the ESG fund are looking for transition funds, are going more for transition funds, the business case of TotalEnergies is probably quite interested to be promoted. All that resulting in quite growing free cash flows, is more than $10 billion at $80 per barrel, but even compared to today, at $60 per barrel, it would be $5 billion. So, and this free cash flow coming from both pillars, oil and gas, oil and LNG is more than $7 billion, and integrated power flipping from minus $2 billion to plus $1 billion will provide an additional $3 billion of free cash flow. So before I leave the floor, a last comment, which is important because one of the, for me, best success today of our transition strategy is the commitment of our people... which makes me very, not only proud, but very confident that we will execute it. Just so we make a survey every two years, and we compare it to benchmarks, to oil and gas benchmark. To be proud to work for my company, 90% of our staff is proud, compared to a benchmark of 72, and it was 88, so it's even increasing. Maybe because I distributed 100 shares to each of the employees on the 100-year anniversary. There may be an effect. I think so, but it's very high, and it's, I think, a big asset. Confidence in TotalEnergies' ability to achieve its transition, 92%, continuing to improve. To all people are more and more convinced that we are on the right track. Working in safe conditions was just to support Vincent's speech. They quite have the feeling that they are in a company who takes care of them. And this commitment to the strategy of the company translates, in fact, into a shareholding. We do annual sharing capital increase reserve for employees, and this year they have invested $500 million. It's a record. So they today own almost 8% of the company. And so I think it's this also important to understand the way we are, why this execution of the strategy is making progress year after year, because we have some very committed employees all around the planet. So having said that, I gave you the headlines of the presentation, and now, Nicolas, then Stéphane, then Bernard, then Stéphane again, will explain you, present you some details, the content of it. Nicolas, the floor is yours. Thank you, Patrick. Good morning, everyone. Let me focus on upstream, particularly. You know, I will start with a key strength of our upstream business is a sustainable, low-cost, low-emission portfolio. First, sustainable portfolio, because as you see in the chart on the left, we managed to keep our reserve life stable over the past few years, you know, at 12 years of proved reserves, 18 years of proved and probable reserves. We've been doing this because we kept our focus on oil and gas. We kept exploring, we kept developing the discoveries, we kept sanctioning new projects. This is important because it gives our upstream business a good longevity. While maintaining the reserve life, of course, we are working on decreasing our production cost, on decreasing our emissions. In production cost, we've been, I would say, leading the pack of our peers in terms of $ per barrel of production cost. This year, we had a target of an upstream production cost below $5 per barrel equivalent, and we are going to deliver this target. We are on good track for the beginning of the year. This is a result of one, high-grading the portfolio, but two, also the work of all our affiliates and teams to decrease the production cost, and I will come back to that later in the presentation. Same effort on decreasing the emissions. You see here the emission intensity, Scope 1 and Scope 2 intensity of our portfolio. We expect to be at sixteen kilograms of CO2 equivalent per barrel this year, versus eighteen last year and versus above twenty-four years ago. And you see in the chart that we expect our intensity to continue decreasing over the year to twenty thirty. Of course, this is a result also of our investment criteria, which are not new, so you know them. They are recalled on the right part of the slide. And all our projects need to have a technical cost, so OpEx plus CapEx below $20 per barrel equivalent or a break-even below $30. And all our new projects need to have a greenhouse gas emission intensity below the average of our portfolio. A key focus in upstream today is the delivery of our projects to deliver the production growth that Patrick was showing. You see here on the slide, the top 11 oil projects of the company, which are going to start between 2024 and 2028. So you see, it's pretty busy. FID this year, Patrick mentioned it, we took FID on four large offshore oil projects: Kaminho in Angola, GranMorgu in Suriname, and Atapu-2 and Sépia-2 in Brazil. Startups three major startups this year, two of which have been achieved already. So we started Mero-2 and Anchor. Mero-3 is to come before the end of the year. Next year, we expect another four major startups in oil projects: Ballymore in the U.S., Mero-4 in Brazil, Ratawi Phase One in Iraq, and Tilenga in Uganda. So what you see is that our portfolio of oil projects, sorry, is not, I mean, it's kind of front-loaded with a lot of startups coming in the next couple of years. These projects, they are well-positioned in the cost merit curve. You see them here, amongst the global oil and gas projects. It's, of course, a result of our investment criteria. And finally, and probably more importantly, these projects are very accretive. You have in the subtitle, the cash flow from operations, the average cash flow from operations from the new oil projects. $30 per barrel in a $50 per barrel low price environment, and $50 per barrel of CFFO at $80 per barrel Brent. To illustrate that, let me bring you for a minute to Suriname, where we were yesterday to launch the GranMorgu development project on Block 58. GrandMorgu, just for you, is a big fish. It's a Goliath grouper, about 2.5 meters long, so like our large FPSO in Suriname, and it's a fish, by the way, that can live for 40 years, so which hopefully will be the duration of our production in Suriname. The first point is this. This project is coming from successful exploration and appraisal by the company. Second, and Patrick mentioned it, I think it's important. We achieved a record one year before the end of appraisal last year on the FID of the project. It's a kind of pace that we want to see now for our new oil developments, one year between appraisal and on FID. This required a new way of working with our contractors, and particularly, you know, we selected our contractors at the very beginning of the front-end engineering phase to be able to accelerate, in fact, the studies and accelerate the FID. So it's a large project. It's a material project. You have the figures in the middle of the slide, 750 million barrels, $10.5 billion of CapEx 100%. It's a project that obviously meets our investment criteria in terms of technical cost, below $20 per barrel. In terms of greenhouse gas emission intensity, it will bring a material production of 85,000 barrels per day upon startup from 2028 on a material CFFO, $1.3 billion at $50 per barrel. The project has a few new technological features to decrease the emissions. It's an electric FPSO, highly energy efficient, with a number of, you know, innovations to improve the energy efficiency. It's going to be also our first FPSO equipped with a full methane detection, permanent methane detection and monitoring network, with a network of sensors. Something that we are going to deploy, by the way, in our other production sites. The good thing about the project also is that we have possible future tiebacks, you know, to extend the production plateau. So there is an upside to potentially further improve the economics. One point I want to mention also, or maybe I will comment it on one of the next slide, is the way we've been working with the contractors on this project to optimize the cost. So now moving to the other side of the Atlantic, in Namibia, continuing Namibia exploration. So first on Venus. You recall that on Venus, after the discovery, we drilled two successful appraisal wells. So we are now progressing the studies on the development of 160,000 barrel per day. There is a material volume of oil. There is also quite a bit of gas that needs to be reinjected. So today, the work of our teams and engineers is to optimize the well's placement, to optimize the FPSO, to ensure that we have a project that is within our investment criteria, particularly with a cost below $20 per barrel. For Angola, we are planning, of course, to follow the same approach as Suriname in terms of working with our contractors early. Future exploration, today we have a drilling rig on its way to Namibia to drill a prospect called Tamboti, which is north of Venus, which was de-risked by a well drilled last year, a well called Mangetti. And beyond Tamboti, we have a number of prospects in the south of our blocks in Namibia, but also in the same basin north of South Africa, offshore, of course, on two blocks, DWOB on Block 3B/4B. So we are looking forward to drill this next year with several actually large prospects that were confirmed by seismic. Let me now turn to what we are doing to reduce our cost both in projects and in operations, and I will start with our CapEx and our project cost. Starting with the first example of what we've been doing in Suriname to reduce the cost by using first you know an existing design for the FPSO. So the FPSO hull is standard hull. We've been using the contractor referential as a basis for design, similar actually to what one of our peers has been doing next door. We've been reviewing, and now we do this systematically, all the equipment sparing philosophy, you know, of the project, to be able to decrease the number of equipment and at the end, reduce CapEx. Another example is Iraq, onshore. Onshore today, what we are really looking at is to decrease the footprint of our facilities. In our gas growth integrated project in Iraq, we managed to reduce by 70% the footprint between, you know, the initial conceptual studies and the status today, which, in fact, brings a lot of saving in terms of site preparation, but also in terms of piping and everything. And we leverage also on regional contractors to keep our cost low. Like in Suriname, we work a lot on reducing the equipment sparing. You see an example here on gas turbines, to keep the cost at the lowest level without compromising, of course, safety and availability. We don't only challenge our, I would say, engineering practices, design practices. We also challenge the way we work with our contractors, and on two examples of that. One you know certainly already. It's in terms of rig ownership, where we decided to acquire 75% of a rig, to hedge rig cost against inflation. And also, today, we work very proactively in all our call for tender to enlarge our contractor base, and particularly to include more non-Western contractors and more Asian contractors in particular. Turning to OpEx. So on OpEx, as I mentioned, we worked quite hard to reach an operating cost below $5 per barrel, so we intend to keep that and to fight to keep that competitive advantage. It's working on three axes. So the first axis is what we call the lean operating model. So lean operating model is about reviewing the organization of our operations on all sites, from production, to inspection, to maintenance, to logistics, in order to execute those activities in a more efficient manner. To reduce our POB offshore, to be able to prepare works onshore, execute offshore, to demand some of our facilities, to reduce the frequency of maintenance, et cetera. On doing that, actually, we get, I would say, a lot of leverage using digital solutions. The second axis is to continue reducing our logistics and procurement cost by rationalizing our logistic bases, by optimizing the way we use our transportation means, by improving the way we do our offloading operations, so logistics and contracts. The third axis is to work on structure cost, and particularly on reducing the structure cost in mature affiliates, typically in some of our North Sea affiliates, Denmark, UK, or West African affiliates, like Congo or Gabon. Overall, our target is to reduce our annual operating expenditures by $500 million per year over the next three years, so 2025-2027. When we look at our OpEx base, it's about 3% per year OpEx reduction, 9% over three years, which will offset inflation. In fact, that's our target, is to offset inflation and keep our OpEx below $5 per BOE. I will now give the floor to Stéphane, who is going to talk about LNG, which is also an area with numerous projects underway. Thank you, Nicolas. Good morning, everyone. I will now present you our integrated LNG strategy, and I will start by reminding you of our starting point. What we have, what we have today, and as you know, we are number three in LNG with an integrated portfolio of around 10% market share. That portfolio is mostly based on the long-term supply, coming two-thirds, well, 60% from our own production and 40% from our third-party sales. Just check if... No, we don't have a map, so. In terms of geography, we are mostly supplying from the US, from Middle East, and to a lesser extent, from Africa, Asia, and as you know as well, Russia. This portfolio is going to grow. This long-term portfolio is going to grow by 50% between now and 2030, thanks to our project, our pipeline of projects. I will present in the next slide. Now, as Patrick has mentioned, we know that a big wave of LNG is coming, and there is clearly a risk that the market is oversupplied by 2027, 2028, 2029, 2030, with a softening of the price. And so the question is, how our portfolio will react to that cycle? And we are convinced that with all the work we have done today, we have a resilient portfolio to go through that cycle, and for fundamentally three reasons. One, our growth is based on projects with low break-even price. Two, we have been able to fundamentally de-risk our revenue to sell our LNG on Brent Index and not on a gas index. And three, we have been able to do that while keeping our optionality in the portfolio and our capacity to arbitrage, not only by bringing our U.S. volume in Europe or in Asia. So we'll start now by the production, and as you can see, we have our growth is based on a portfolio of projects which are mostly under construction, and we start up which will come from early 2026 to 2028, 2029. Most of them being currently under construction. If you look at them, so you've got two projects in North America, Costa Azul in Mexico and Rio Grande in the U.S. Costa Azul being a competitive project because of its location and saving, because it's on the Pacific Coast, and Rio Grande being one of the most competitive project in term of liquefaction fee, it will be the best in our portfolio. Then you have two other project in Middle East. One is Qatar. Qatar is well known as the cheapest gas in the planet, the most competitive LNG, and we have been able to join both North Field East and South expansion. And we've got as well the Marsa project, which is a small one, one million ton, but as mentioned by Patrick, we have 80%, and that's a fully electric drive project, fueled, by the way, by green electricity as well. So in terms of CO2 content, that will be probably one of the best in the world. Finally, you have Train seven, which is benefiting of the synergy with the first six train in Nigeria and Mozambique LNG, that you know quite well. And then two other projects that have not yet been sanctioned, Papua LNG and Cameron Train four. And the reason why they have not been sanctioned, because we are not satisfied by the level of CapEx we have reached so far, and so we have going through a process of re-tendering to see if we can improve the CapEx and sanction them. Where does that leave us? That leaves us with a range of projects which are on the left part of the merit curve, so it's not, it's not ours, it's Goldman Sachs one, and where we have mentioned where we are with very competitive projects in the Middle East. Nice, and nice one in the U.S. in that, in that curve, assuming that Henry Hub at $3. So that's for the production. I move now to the sales, and on the sales, what have we done in 2024? What we have done in 2024 is fundamentally to try to sell our LNG in Asia on a Brent index, on the Brent index, and you see that we have already achieved four million tons of sales. That's a public one. Actually, you've got a few other coming very soon. And we have been able to do that, increasing our market share in China, notably with CNOOC, in Korea, with a small player, but nice contract, KOEN and Hyundai, and in Singapore and in India. And so those sales are mostly on Index Brent with actually a nice slope. So where does that leave our portfolio? And you've got that on the left part of the slide. If I look at 2024, the left column is on which index we are buying our LNG. It could be spot price, JKM, TTF, it could be Brent, or it could be Henry, typically, if it's sourced from the U.S. And on the right side, you have what we have committed to sell. We can sell on Henry. Typically, we have some contracts in Latam where we are selling on a Henry Hub basis. That's one. We can sell on Brent Index, typically what we are doing in Asia. And then we have some contracts that are DES Europe, where when you are DES Europe, by definition, you sell based on TTF. That doesn't mean that you can't reload, but the destination of your cargo is Europe, so your index at the beginning is TTF. And you see that we could be in a situation where we have more supply than sales. The difference is something where you can decide actually to sell it on the various market. If you wait, but you sell it in spot, and if you don't wait, you can try to sell it on a typically a Brent Index. What is interesting is that we see that our supply based on Henry Hub is going to increase a lot. Not that much for the Brent and a bit for the JKM. And you can see that on the sales side, what we have done was to increase significantly the volume of LNG we are selling through a Brent index, both in 2028 and 2030. Why have we done that? And that the right part of the chart is to look at the net difference between the sales and the supply. And when you make that net, you see that fundamentally, the exposure of our portfolio in 2024 is to buy Henry Hub around five million ton remaining position, and to sell that two-thirds on the JKM TTF index and one-third on the Brent index, which means that we have been able to benefit from, as Patrick was mentioning, the $12 of TTF. With the evolution of the portfolio between the contracts we sign and which are all starting in 2027, 2028, you see that in 2028, fundamentally, we will be buying and buying Henry Hub and selling only Brent without any more gas exposure. And in 2030, that's not yet the case, but we are, as I said, working on it with that idea that we will, on one side, buy Henry rehub and only sell Brent. Two additional comments I would like to make is the fact that we have the view that the market will be with TTF softening price by 2030. It's not necessarily going to last forever, and our contracts are not lasting forever, which means that by 2032, 2033, you've got contracts that are for five years. You could find back your gas exposure if you wish. That's one. And second, it's not because you sell long-term index Brent in Asia that you lose your opportunity of arbitrage. You can still continue to divert cargo between Europe and Asia. So to conclude, where does that leave us in terms of quantity and cash? We have put here a comparison between where we are this year, 2024, versus 2018, sorry. Why have we chosen that? Because that's in terms of price, in terms of Brent and gas, quite similar year, and it's not polluted either by the COVID or by Ukraine war. So if I look at the past, what you can see is that we have been able in the last six years to grow significantly our portfolio from 18 to 30 million tonnes. And that growth was actually accretive because our cash was multiplied by 2.2 during the same period, if you really restated by the price. So that's for the past and that the intrinsic improvement of our portfolio. And then when I look forward, you see that we are pretty much going to increase by 50% our volume. And at the same time, because we are relying on a really low-cost project, we plan to double our cash flow generation. That's one, and second, the way we do that is by limiting as well the sensitivity of our portfolio to gas, because fundamentally, we will be mostly selling on the Brent index. And you see that the resulting sensitivity of the cash to the Brent price. In summary, a resilient portfolio through the cycle, thanks to one, low-cost break-even project, and second, de-risking the sales by selling index, Brent link. And I will now hand over to Bernard. Thank you, Stefan. Good morning, everyone. Let's move now to downstream. So as you know, over the past years, downstream has been a segment which has been a steady contributor to the free cash flow of the company, and this has been achieved while transitioning, executing a strategy made necessary to meet a triple challenge. One, of course, is to adapt in Europe to a lower market demand for oil product. Secondly, to reduce our CO2 emissions worldwide from our operations, and third, of course, to provide and develop for our customers low-carbon solutions. How are we executing this transition strategy? First, we set ourselves a target, I'm sure you will remember, to align ourselves to our production, to get to a higher integration along the value chain, and of course, to enjoy a more balanced profile between upstream and downstream. As you see on the left-hand side of the chart, in the past, by 2019, as you see, we used to sell much more than what we refine and refine much more than what we produce. And since 2019, things have changed. We have made a lot of progress because we have reduced our refining capacity by 15%, and we have also reduced our product sales by more than 30% to concentrate on the most valuable part of the portfolio. And as of today, you see that we are well on track to meet this target, to be balanced between upstream and downstream by 2030. All this transition strategy, of course, is executed in the framework of a very strict capital discipline. And if I start with refining chemicals, it means that we are allocating our CapEx to projects which enjoy the lowest break-even points to be resilient across cycle, and that's true notably for petrochemicals, where we invest in project benefiting typically from cheap feedstocks, ethane, LPGs. A good example being our projects in Saudi Arabia, the Amiral project. That will be a world-class petrochemical platform downstream from our SATORP refinery that will start in 2027, and there we enjoy from very cost advantage feedstocks in the kingdom. That's true also for our sustainable aviation fuel projects, where we leverage our existing assets, our existing refineries, to develop low CapEx projects, but I will come back to this in a few minutes. For marketing and services, here again, we favor a strategy that we call value over volume. It means that, for example, in our retail network, we concentrate on the geographies where we enjoy leading positions, mainly France and Africa. And in our high-end specialties, we focus on the high-end applications, notably in lubricants. But once again, I'm gonna come back on this in a few minutes. So all in all, we have as a target to deliver by the end of a decade, an additional $1 billion of free cash flow in the downstream segment. So what I would like to do now is to give you a little bit more specifics by going through some key projects. I will start, of course, with cost savings. Not a surprise in refining chemicals because cost savings is of essence to lower our break-even points in a cyclical industry. And if I start from the left, of course, energy, energy cost is one of the main, if not the main cost centers in refining chemicals, and this is where we have to work to be cost competitive and also, of course, to reduce our CO2 emissions. In 2023, we launched worldwide an energy saving plan. We even called it Energy Savings Acceleration Plan, of $1 billion to be executed over 2023-2025. And out of this $1 billion, $400 million were dedicated to refining and chemicals. I must say that it has been a tremendous success with a huge engagement from our employees, including on the field. We have been able to identify close to 250 projects, such as, for example, recovering heat waste to be used in preheaters for steam crackers, electrifying with green electrons compressors which were operating with steam before, or, for example, reducing the fouling in heat exchangers. There are many, many examples like that, and at the end of the day, all of this translated into $100 million a year savings, as you see on the chart, and 1 million tons of CO2 reduction. The good news is that by doing this exercise, we identified much more projects, many more projects with good payback, and we therefore, we decided to launch a season two with exactly the same metrics. $400 million again to be deployed in 2026-2028. We've already identified, again, $100 million of cost savings in energy and 1 million tons of CO2 emission reduction. That's for the variable part, so it's very significant. But of course, we need to work on the fixed cost part as well, which is once again, a key metrics, when it comes to talk about competitiveness. And here I would like to show how digital help us reduce costs, notably in the field of maintenance and inspections, which are, here again, one of the main cost centers in a refinery. Let me give you just a couple of examples. If I take the innovative unmanned technologies that you see on the chart, the example is very straightforward. We use drones and robots to inspect tanks. By doing this, we avoid putting in place scaffolding, which, you know, are first, very costly to put in place, but which also bring a long period of unavailability of the assets. So by doing this, we save a lot. And last but not least, we also operate in a much safer manner. If I take the example of the IoT, a good example here also is the usage of IoT in the field of predictive maintenance. IoT allows the deployment of a predictive maintenance on rotating equipment, and that helps prevent early machine breakdowns, of course, and reduce unplanned downtime. So all in all, I could give you many more examples, but at the end of the day, all these projects translate on the fixed cost side by a saving of $200 million a year, $200 million over the period from 2024 to 2027. And as you see, by doing this, we will be able to offset the inflation over the next three years. Let's move to marketing and services. As I said earlier, our strategy there is pretty simple. It's value over volume. What does that mean? It means first, if we look at the retail networks, that we want to create value by concentrating on the geographies where we enjoy leading positions. That's, of course, in Africa, where we are the leading petroleum products retailer on a continent which is enjoying a growing demand. It's a no-brainer. In Europe, we are also refocusing our strength, our presence in the country where we are a leader, mainly in France, namely in France, where we leverage our leading market positions to grow our services in the field of non-fuel sales, you know, food, cars, car wash. The second pillar is around the lubricants. Here, we will create value by developing a product offering on the high end of the market, where we command higher margins, and we intend to grow also our range of sustainable lubricants, and this will be done notably through the acquisitions we have made a few months ago of a Finnish company called Tecoil, which is a producer of re-refined base oil, and that give us now the pro... The ability to provide to the market some circular lubricants. The third pillar is around the electric vehicles, of course. Here, we want to create value by concentrating clearly on the development of fast charging points aimed at serving the on-the-go customers, the one who are willing to pay more, commanding better margins, with hubs located in urban areas, HPC located in our service stations along the highways. And we also intend to develop what we call low equity business model through partnerships and leverage. The last example of how our transition is going to generate more cash is our development in the field of sustainable aviation fuel. Here, we are developing this strategy around three pillars. The very first one on the left-hand side, which is key, is around the feedstocks and the need to secure these feedstocks. As you know, in Europe, only given feedstocks such as waste and residues are eligible for the production of SAF, and this resource is limited. Therefore, it's critical to secure it, and we are doing it through integration or through a longer take agreement with suppliers. A good example of a recent move we have made is this partnership with SARIA. SARIA is a German company. It's a European leader in the collection of animal fat. And we have made with SARIA two joint ventures, one upstream, where we have taken 50% of their one of their company transforming animal fat into biofeedstocks. SARIA, on the other side, has taken 50% of our projects in Grandpuits biorefinery to integrate themselves downstream, and by doing this, we have built a winning combination and secured clearly the upstream in terms of feedstocks. Of course, we also leverage our trading capabilities to enlarge the pool of accessible feedstocks, and we are doing it, of course, by making sure that we only source certified, sustainable biofeedstocks. The second pillar, which is also of interest, is how we are going to produce this SAF to be low cost, because that's really of the essence, and here we are made two clear choices. The first one is that we want to produce by doing co-processing in our traditional fossil refinery. So what does that mean? It means that we directly inject the biofeedstocks into the jet fuel processing units. We produce a blend which contain a certain percentage of SAF, and this blend can be directly incorporated into the airplanes. The beauty of this is, of course, that it only requires a few process modifications and very limited upfront CapEx. So it's a very, I would say, smart and low-cost way of doing SAF. By 2025, we will produce, by co-processing, 160,000 tons of SAF in our Normandy refinery, and we are about to start in a few weeks from now. The second choice we have made when it comes to producing pure SAF this time is, of course, to retrofit existing refineries into biorefineries. And by going this way, retrofitting instead of going to greenfield projects, we enjoy much lower CapEx. The CapEx intensity of a retrofit is 40% lower than the one of a greenfield project, and this is why also we may benefit, enjoy very low cost and low CapEx-intensive project. And that's what we are doing in Grandpuits, the project close to Paris, where we are about to start up, because next year, in 2025, we will start producing 200,000 tons of SAF, and that will be even 300,000 tons by 2027. So we are going, I would say, both ways. The third pillar in this growth strategy around the SAF is, of course, to leverage our market positions with our customers: airlines, Air France-KLM, OEMs like Airbus. We cooperate with them to develop, to design the next generation of SAF, of course, and leveraging our logistics footprint and setup, we secure also with them long-term supply agreement. This is, for example, what we have recently done with Air France-KLM, as we announced last week, if you remember, that we will provide Air France-KLM with 1.5 million tons of SAF over the next 10 years. In conclusion, what I would like to say is that through these few examples, you see that the downstream segment has a clear transition roadmap, and is well on track to execute it, to deliver this additional $1 billion of free cash flow by 2023. Now, I leave the floor back to Stéphane. So I will now move to integrated power and how we plan to, or we are currently building a future cash engine. By future cash engine, we mean ROCE above 12% by 2030, as explained by Patrick. To do that, the first objective is to reach above 100 terawatt hour of production by 2030. It's not growth for growth. It's just that growth means that the business will be of size equivalent to 500,000 barrel, and that we have bargaining power with the supply chain. That's one. Second, we want it to be integrated. What do we mean by integration? That means renewable asset on one side, flexible asset on the other side, and you see that the idea is to have roughly one third of solar, one third of wind, and one third of CCGT. By definition, you can only deploy that model on deregulated market, and that's why we want to focus on the U.S., and in U.S., Texas and PJM, Europe, Brazil, which is as well an open market, and India, which is currently opening. The rest of the world will be mostly oil and gas, where you have a synergy with the rest of the portfolio. And all in all, the deregulated market should be around 70% of our production. When I look at how we are going to achieve that on the renewable side, so today we are end of 2024 24 gigawatts. We should be at 35 by end of next year, with what we have in construction and what we are currently sanctioning. And if I look between all our JV with Clearway, Casa dos Ventos and and AGEL, and on my own operation, we've got a pipe of roughly 90 megawatts of different type of project and different maturity, and we assume that 50% of it will materialize. The rest, it's either that we won't get the permit, or we decide that it's not good enough, not profitable enough, and we prefer to sell them back. So 35 plus 45, that gives you roughly eighty 80%. 80% of that pipe is already identified, and the idea is to complete that with selective M&A, notably to work on the integration and notably to improve the level of wind we have in our portfolio. And you see that we want to reach roughly 50% of capacity in solar, 40% in wind, and 10% in battery. And I note, by the way, that offshore wind will remain only 10% of our portfolio. Now, if I look at the flexible assets, on the flexible side, what we want is really to work on the integration. And that integration between gas production on one side and flexible generation, between flexible generation and renewable generation. When I look at the downstream of the value chain, is to work between production and trading and sales, access to the wholesale market, where we plan to sell 30% of our production on a merchant basis, and customer for the remaining 70%, and I will come back to that with Clean Firm Power. As you know, we were already integrated in France, where we have some CCGT. We were as well integrated in Spain. We have worked in 2024 on that integration, and that's the reason why we have purchased some CCGT in Texas and in the U.K. We have purchased as well some battery business in Germany to work on that integration along the value chain, and that's something we are going to continue to do. You see that when it comes to Germany, it's clear that besides our position on offshore wind, we should try as well to develop onshore solar and wind production, and as Patrick mentioned previously, we would be happy as well to have some CCGT on the portfolio. Why do we want to have that integrated power portfolio? One, it's because it's good to seize trading opportunities in the market resulting from the volatility of the market linked to the intermittency of electricity. But two, because we can generate value by selling clean firm power. So what does that mean? Five years ago, customers were buying guarantee of origin, which means that you were buying electricity in Texas, and to say that it was green, you were getting guarantee of origin in India. There is absolutely no link between both. So people have started to move and buy corporate PPAs produced, which means that they identify the solar farm, they buy the green electrons from that solar farm. But the truth is that that solar electron doesn't meet their need, because they need baseload, they need something that is shaped to their consumption. What we see more and more, at least in Europe, is that customers get burned by buying corporate PPA power, because they are unable, in an efficient way, to transform those corporate PPA power into what they need. That's where we come with an ability to tell them, "Okay, I'm going to sell you the electricity you need, and that electricity is going to be green." The way we do that is that we provide electricity on one side, and we provide the guarantee of origin, of a renewable production, of an identified solar or wind farm. If they want that to be in the same region where they are, we could do it. If they want that to be additional, a new investment, we can do it. Obviously, by doing that, we are taking some risk because when there is no renewable production, but you need to provide power by producing it, and that's where you need a CCGT, for example. And when you have extra electrons, you have to resell them, but that's exactly the type of risk we are used to manage. And the fact that we are fully integrated along the value chain allow us to to do it in a very efficient way. And so we have started to sign a few contracts on that and plan to do more, where we can see that we can extract premium from the development of clean firm power. I've mentioned, so why we believe that integration and clean firm power sales will help us to to reach our objectives. There are two other pillars on which we are working. I won't detail them today. One is industrial journey, where we want to be the best in terms of OpEx and CapEx, and when we've made good progress in 2024, notably in terms of supply. As you know, we are targeting to be in CapEx and OpEx in the second quartile at least, targeting to be first quartile. From our benchmarking, we know that we are already second quartile in the U.S., but there are still at least 10% cost cutting cost savings that we should be able to do. So that's for the first pillar. The second pillar is to continue to work on the farm-down. This year, normally at the end of the year, we should have been able to farm down around 1.4 gigawatts of assets. Some have already been done, like Seagreen, and others are on their way. With those three pillars, cutting, saving costs on OpEx and CapEx, better sales with merchant exposure and clean firm power, and portfolio optimization, we are confident that we will reach a target above 12% of return on capital by 2028-2030. Where does that leave us in terms of volume and cash? You see that on one side, we are currently at around 40 terawatt-hours of production. We should be above 100 by 2030, with 70% renewable, 30% flexible. In terms of cash, we should be able to maintain the level between 2.5 and 3 in the coming year, 2025. Then, that cash flow should progress with volume, with the idea to reach above EUR 5 billion by 2030. All that being free cash flow positive by 2028. I leave now the floor to Helle from Asia. Helle, floor is yours. Thank you, Stéphane, and good morning, everyone. I hope you can hear me okay. I just wanted to share a few words with you on Asia and our growth in the region, where I have been based for eight months now. Next chart, please. Asia is the heart of the energy markets growth. Why do we say that? Very simply because Asia fuels the world's economic growth, Asia fuels the world population growth, and therefore, Asia fuels the growth in energy demand. As you can see, Asia's primary energy demand grew by 2.6% over the last decade, which was twice as fast as the global growth rate. Going forward, the challenge will be to enable emerging Asian countries to reconcile the high growth in energy demand, which is an absolute certainty, with less emissions. We show here two scenarios from the IEA on Asia's energy demand in 2030. Continuation of the existing trends, which is STEPS, and the APS trajectory, which is a well below 2-degree scenario. Whether you believe in one or the other of these two scenarios doesn't really matter. The net message is that Asia offers huge opportunities for a multi-energy company like ours, linked, of course, to the pickup of clean energy. Renewables to cover growing power demand and LNG to back out coal, and those are, as you know, our two growth pillars. Next chart, please. With that in mind, Asia is set to be a major outlet for the next wave of LNG supplies coming on stream between 2027 and 2029. You see here the growth in Asia's LNG demand between 2015 and 2021 was 8% per year. Then you see the dip in demand in 2022, when Asia had to compete for available LNG cargoes with Europe, and since then, renewed demand growth with a nice upward curve. Asia represents roughly 70% of the world's LNG demand, and we do expect strong demand pull from the region between now and 2030. As you heard from Patrick, softening prices will trigger additional demand from price-sensitive countries such as India and Southeast Asia. That is precisely what we have seen in past cycles. To the right, we show the expected growth in our own LNG sales, and as Stéphane told you, we have signed four million tons of long-term contracts with Asian customers this year to date, and there is more to come. These contracts are largely oil indexed. So in summary, on our LNG sales in Asia, it's strong growth with good price formulas. Next chart, please. Moving on to India, which is a good illustration of the opportunities I mentioned, linked to developing Asia's opportunities and growth around our two pillars of LNG and renewables. We are very well positioned to capture growth in the Indian LNG market, thanks to our participation in the infrastructure for LNG imports and in the city gas developments together with Adani. Likewise, we have a strong presence in the Indian renewables market via our 20% shareholding in Adani Green and via the direct participation that we have in asset owning JVs, where we invest 50/50 with Adani Green. These JVs total four gigawatts of capacity at present. India is gradually liberalizing its markets, its power markets, which enables us, therefore, to selectively grow our merchant exposure that Stefan was just talking about, and which is clearly part of our value-creating business model. I also want to stress that India plays an increasing role as a state-of-the-art competitive supplier base for us, be it for equipment such as PV modules, EPC contracts, or digital services. Next chart. Now our last chart, just on Malaysia. As you know, we're about to close the acquisition of SapuraOMV, which is a sizable gas producer in Malaysia and the operator of the PSC SK508. We're talking about low cost, low emission gas in line with our investment criteria, of course. This acquisition will add some 50,000 BOE to our production as early as 2025, and we also have a great platform for future growth, coming both from existing discoveries and future exploration. So we're excited about this acquisition, and it will, of course, also consolidate our long-standing partnership with Petronas, with whom we have multiple JVs around the world, and also a recent partnership for CCS in Malaysia. And with that, I will hand over the floor back to Patrick. Thank you. Thank you, Helle. So the digital works within TotalEnergies. The connection between New York and Tokyo was perfect. We avoided you to spend a lot of CO2 coming back to you to New York for seven minutes, and you have been perfect, Helle. Thank you for sharing these ideas with us. So to come to finalize, to conclude, why should you continue to increase the investment in TotalEnergies business case? I think first, I remind you that we have some fundamentals, you know, which are strong. In particular, the break-even of the company before dividend is $25 per barrel. It helps a lot, of course, when we consider potential volatility on the oil price in coming years. It's a fundamental which allow us, of course, to... It's linked as well to a second characteristic of the portfolio, which we have highlighted, is that we have and people sometimes see TotalEnergies as a resilient company to low price, but we are also capturing upside, a price upside. You can see that, compared to we have moved the portfolio to much more higher cash flow per Brent, per barrel of Brent, I would say. And and we can compare the performance of the year 2021, 2022, 2022, 2023, 2024, compared to the same Brent price, so performance before up to two thousand and four, two thousand and eighteen. So that's the second point. And all that has underpinned higher shareholder returns. We have taken a commitment from since last year that the payout ratio should be above 40%. We deliver more than 45-46% last year, 48%, 2023. We are above 45%, for this year as well. What we describe to you is the same slide I introduced at the end of my first part, so I will not comment it again. But, this is the energy, I mean, this is a transition business model of TotalEnergies. We grow, our energy production, we diminish our emissions, including the carbon intensity of all our energy sales. So we are a transition, business case, I would say, and we deliver more free cash flow. And I hope the presentation of Nicolas, Stéphane, and Bernard have convinced you that this additional $10 billion of free cash by 2030, will be, material and have some clear, I would say, ground, strong reasons to be, presented to you today. And again, I insist that even if the price were at $60 per barrel, the additional free cash would be $5 billion. So you can see the impact of the sensitivity. If I'm translating all that, and I know that Jeanine in the room and Renaud love this slide, into a cumulative free cash that TotalEnergies will be available, will be able to share with, I would say, its shareholders and which will support growing distribution. We start our. So it's 2025, 2030, it's six years of cumulative free cash. I'm commenting first the one at $50 per barrel. On the period, we are, I would say, the CapEx has around $100 billion, which we presented to you. In the $50 case, we have considered that we could, if it was really six years at $50, I think we would exercise, of course, the flexibility we have downwards, so it's a little lower than the $100 billion. We add on it without growing it in this chart, so it's just the 2024 dividend, the existing dividend, which represents more or less 7.5, let's say $46 billion on an annual basis, on six-year basis with no growth. But of course, we don't intend. There is no message there, you will see. It's just a math to show you that we have space not only to increase the dividend, but to also maintain our shareholder return. The first message on the left is that, in fact, our post-dividend break-even is lower than $50. It will be in twenty-five, I think it's around $45 per barrel, so keep that in mind. And so we are lower than $50. The second one, at $80 per barrel, is that we would generate under ten, more than $110 billion of free cash flows. At $60, it would be $80 billion. So of course, if you make some dividend growth and you have, you can see some math, that we could continue to maintain at $80 per barrel. We could continue to maintain the, I would say, $8 billion per year program that we have put in place consistently for the last 10 quarters. And there is even more if you make the math for improvement. Improvement of the dividend, spending and maintaining at least this $8 billion buyback program. That leads to this chart that you know quite well. We do not change the order. I just wanted to comment to you, which is a way that the board looks to the cash flow allocation. First, of course, the dividend is our primary. I would say to maintain a sustainable ordinary dividend through cycles. We didn't cut the dividend in 2020. I should say, by the way, when I was looking to the figures, that compared to pre-COVID dividend, we have increased it by 20%. We are second, in fact, in the industry. There is only one U.S. company which has done a little better. We are doing better than the other US company and far better than our European peers, who have diminished by 25% compared to pre-COVID dividends. So, we have done 7% the last two years. Today, what I'm telling you is just applying the policy that the board is committed to, which is, in fact, next year, which will increase at least by 5% the dividend, because we will buy back in 2024, more or less 5% of our shares. So mechanically, we'll increase it at least by 5%. We'll take the decision about this increase by February, so we keep some the board to decide according to, I would say, the final results of the year and the perspective. The CapEx, I commented that. The balance sheet is strong. We have a 10% gearing by the end of the first half. There is a working capital build on which Jean-Pierre Sbraire and all my colleagues are working hard to diminish it. We should have a build of working capital this year, because last year, because of the high prices, we benefited, I would say, from $2 billion of exceptional decrease of the working capital from links to fiscal positions in different countries. But we should have some diminishing of this working capital before year-end. And the last one is the buybacks. On the buyback, we have consistently bought back $2 billion per quarter. So I confirm you that we'll maintain this two billion quarter of dollar for the last quarter, and so we'll buy back $8 billion this year. We have the board. We decided to announce you today that we'll continue on this pace of $2 billion per quarter in 2025, assuming reasonable market conditions. It's better than current market conditions. Lower, I would say, than current. So that's the discussion. Because why? Because we know that investors are looking to appreciate this buyback from oil and gas companies. And second, because again, the gearing being low, we can, I would say, leverage this gearing in order to maintain our pace on $2 billion per quarter in 2025, assuming reasonable market conditions. All that, again, will lead to maintain this more than 40% payout through the cycles in 2025. In 2024, we should be above 45%. So we have a performance, I would say, which the share of TotalEnergies has done well in the markets. We have an earnings per share, which is at 6%, I would say, compared to our peers, so it's quite good. And we have a TSR as well, which has, since we take the last 10 years, has offered good returns to our investors. I take just one minute to comment on this slide. As you know, we are working on a project which is to transform ADRs into certificates, which are today the base of our U.S. listing, into ordinary shares. So we are already listed in New York. We just want to transform these ADRs into ordinary shares because it simplifies management for our U.S. shareholders, removing some ADR frictions, and it will be likely to improve the liquidity of the TotalEnergies security. Just to be clear, because I know that what I'm saying today will be listened to in Paris. Paris will remain the TotalEnergies shares introduction market, but we are working, so it's a work in progress today, on all the technical aspects with both European and U.S. central securities depositories, Euroclear and DTCC. The board supports unanimously these projects of transforming ADRs into ordinary shares if it's technically feasible, because it requires some IT development and certain delay to be operational. So it's a work in progress. If it is technically feasible, we intend to make this transformation. I remind you that ADRs represent 9% of the shares of TotalEnergies today. So it's more a question of being able to offer to US investor, I would say, an instrument which is easier from a financial point of view, from an investment point of view, like our European investors. And it will not be a revolution, but of course, it's contributing to the liquidity of TotalEnergies security. And finally, to conclude this presentation and to summarize what we said today, I introduce it. This slide is concluding it. We have, I think, a very deep portfolio of upstream opportunities coming from both exploration, which is strong, which is good, like Suriname, and I know that all the teams in TotalEnergies are very proud of the Suriname project, but also from some targeted M&A we have done in the last years. It's now offering a de-risk, I would say, high margin growth perspective to our investors. And starting from twenty twenty-five, we have bet that through strong on LNG market, and we consider for the long term, it's quite a strong position, and we are de-risking the exposure to spot gas to manage the LNG wave we will face by the end of this decade. Our integrated power business is developing its integrated business model. I insist on the role of gas in our strategy, because fundamentally, this is the link. We consider that natural gas will be one of the transition fuel, coping with renewable intermittency, but also enabling the decarbonization of part of the power cycle itself. We have some fundamentals, discipline, CapEx and OpEx. We are a low-cost operator and portfolio. Break-even is controlled and a strong balance sheet. And all that, all in all, allow us to again consider that we'll continue to grow dividend and sustain share buybacks for the year to come. Thank you for the attention, and we'll be happy to answer to your questions. Okay. Let's move to the Q&A. So the rule is very simple as usual, you raise the hand. So Michele raised the hand already. Michele, go ahead. Thank you very much, and thank you for the insightful presentation. There were two questions I wanted to ask. One, which partially relates to recent news flow. We've seen a bit of an emergence of fiscal instability again in Europe. We had the change to the U.K. taxes, and now we have some announcement in France. I was wondering if you had any comments on that or any potential quantification of the impact. Secondly, I wanted to ask you on technological innovation. There's a lot of questions about AI, digitalization, how it changes the sector. I think you were presenting at the SLB Digital Day last month. I was wondering, do you see this just as an evolution of what has been an ongoing improvement in efficiency, or could this be a breakthrough, especially in recovery rates and discovery rates from a seismic and exploration perspective? Thank you. Interesting. First of all, I was in Suriname. I listened to the Prime Minister's speech yesterday. There was no big announcement. They said they want to, unfortunately, to increase taxation in our country in France rather than cutting spending, which I think is more expected by markets. You should go and explain. But on our side, I would say first, two comments. The income tax is based on the revenues in France for TotalEnergies. You know the magnitude of that. It's quite limited, so I don't expect much impact on us. Second, there is a debate about share buyback taxation, and according to what I know, what is considered is a levy. Is even if it's a little conceptually different for different reason, the level of the 1%, which is today applied in the U.S., is considered as a base of the discussions today. So honestly, you can make the math. For us, it's around. It's not. It will be 1% of the buyback, probably. But even it will not be expressed like that because they are more willing not to tax at the when we buy back the shares, but when we reduce the capital. So there are some technicalities. So the percentage which might appear in the news will be higher, but in fact, at the end, it will be sized to be more or less in line with the 1%. And it's difficult for me to argue against it because your U.S. taxation have it happened. That's where we are. The situation in the U.K. is much more problematic because it has not only a higher impact, but there I'm taking that very seriously because clearly we'll be very selective on any CapEx we will spend in the U.K., and we are clearly looking seriously to ways to restructure operations. So it's very different. France is not an oil and gas country, so honestly it has limited impact on our businesses, I would say. On the UK part, it will have an impact, clearly, on our UK investments. If we are waiting for their October thirtieth, there will be a big speech by the Prime Minister or Chancellor of the Exchequer in the UK, which will impact, of course, the follow-up on this, on the position and what will happen to us on our position in the UK. I'm arguing with them that they should copy-paste the Norwegian system, which is maybe high fiscal, but incentives to invest. If we lose, if we have the high fiscals without any incentive to invest, I'm afraid the production in the UK North Sea will diminish quickly, which is not the interest for me of the country, but that's it. That will be the choice, and we will respect the choice of the country and draw the consequence for our business there. Technology, for me, there is something happening. It's a revolution, in particular in terms of speeding up. I was convinced by a discussion with the head of French meteorology, who explained to me that the model of meteorology, which was running five days before today, it's one hour. And Google becomes probably one of the best because of AI. So there is a revolution. So in fact, it's speeding more than... Honestly, I don't think the AI will discover oil alone in the ground. For once, I will be surprised. But speeding and in particular, designing projects. I'm sure that today we spend quite a lot of time to view and to review, and not only we should more copy-paste what contractors does, but even build, and we reinvent the wheel in many ways. I think with these type of tools, we should be able to accelerate the process, and so for me, it's something and there is a new thematic. In fact, in our company, we have done a lot historically on subsurface data. You know, we acquire, we spend a lot of money, so seismic data, managing the data, modeling, using them, and we need should know, we should seriously think in our companies to do the same on the digital plant. The digital plant will be, for me, a source of efficiency. We were speaking about fighting inflation cost. This technology should help us to accelerate on it. So it's more using, shortening the time, if it can... But again, there is somewhere in your question, I'm convinced that reverse modeling, when you speak about physical models, which are not so efficient, if you have a lot of data, you could make some reverse modeling and reverse modeling by AI could be, could deliver to even to Vincent in his refineries. You know, all these LP models, linear models, are not so, not so efficient. We could be much better if we are able. But to do that, we need to have digital plans to acquire the data. And so that will be an axis of investments, and we are working on it for the next year. Okay, let's go this year end. Yeah. Yes, this is John Abbott from Wolfe Research. I'm here for Doug Leggate. We had a couple of questions on Suriname. Could you explain the $1.4 billion dollar plateau at $50 oil? Does that include capital cost recovery, and can you confirm whether or not you might have gotten better FPSO terms at FID? And then for our second question is: you've talked about a four-year plateau. What's your visibility on possibly extending that? Yeah. First, yes, it includes the cost recovery, obviously, which will be recovered in five years at a reasonable price. Yes, we have improved some terms. Yes. And the second question is. Now, in particular, what we insisted on it, there are several terms. So I will keep that within the authorities and ourselves. In particular, we have, I would say, better terms when the price is under $60 per barrel, just to protecting the low part. And secondly, which has big importance in my eyes, we have a large development areas, and we will be able to amortize all the exploration on the first projects as we could go tomorrow. Why is it important? It's linked to the last question you raised, which is: Can you extend the plateau? Yes. There are, like it was said by Nicolas, some targets 50, 100 million barrels of oil, which are in this, in the facility of this hub. For me, the GranMorgu FPSO will become a hub, and as we can amortize more exploration, you know, we made other discoveries in that block, but will incentivize us to look again to this discovery. So I think we are in a good position, yes, to extend. Clearly, we see some upside. And secondly, to maybe develop more resources in Suriname. So we negotiated terms which are in the interest of both parties. Hi. Hello, it's Martijn Rats, Morgan Stanley. Wanted to ask you two things. First of all, on the buyback guidance for 2025, you mentioned assuming reasonable market conditions. I know it's an impossible question to answer, but you can see where this is going. Could you sort of elaborate a little bit on what the boundaries of reasonable market conditions are? It sounds like sort of 70-dollar Brent, but of course, other things like refining margins also play into that. And then secondly, I wanted to ask about Namibia. There was a figure of 160,000 barrels a day of oil on the screen. But I was wondering how much gas comes along with those 160,000 barrels. That one in particular. Yeah, thanks. Okay, on the first one, I don't know if you have asked a question to our peer who has exactly used the same sentence, assuming reasonable market conditions. It's lower than $70. So $70 for sure, but in our mind, it's with the board, we have. It's lower than that. Okay, we can sustain this $2 billion per quarter. You are right, it's a combination of oil, gas, refining margin, but generally, when the oil going down, the refining margins, margins are better. So I would be surprised to have everything going in the same direction. And as a gas price for me in 2025 should remain more in the range of this, what we experience today, I'm confident on it, about it. We could have it lower than $70 in the mind of the board, and we discuss it with different scenarios, precisely. Just to answer to your question. That's why I can say today, $2 billion per quarter in 2025, you can take it as an assumption. Then, of course, if we are at $50, you will see us moving, but it's not reasonable market conditions. Okay? Second one. Now, the gas is. There is gas. Again, the gas story is not a matter of. It's a matter of being able to reinject all this gas in the reservoir at a cost which is acceptable. You know, there is the GOR of this Namibia discovery, for example, compared to Suriname, is higher. In Suriname, we are reinjecting the gas, and we do it with acceptable cost. There you have a higher GOR, so that means that the machines are, to reinject are higher, and you need also the reservoir needs to absorb this gas, and we don't want to flare. So that's where we-- it's a combination for me of costs and this gas, where we are working on it. Remember that it's $20 per barrel or less than $30 breakeven, that we are, which are objective, so we are ways to accommodate it. We might engage into discussion with the Namibian authorities like we've done with Surinamese authorities. We have the advantage in both sides to be the first mover. So the first mover is quite welcome, and answering to your question, it's easier to discuss about condition when you are the first mover and maybe in the Suriname, by the way, the only one, the large ones, you know? So that's where we are working on it. So that's what I can tell you today. Okay. All right, yeah. Go for it. Yeah, thank you. Paul Cheng, Scotiabank. Two questions. Patrick, I think in the past you have said Total knows how to sell gasoline and diesel, but it is not very good in selling trinkets and all the other products. But here today, you're saying that you're going to leverage your France position in trying to do far more in the non-fuel sales. So why do you think, given your previous comment, that you have the maybe the talent and know-how to be in that business to be successful? And given people are still willing to pay a fair amount of money for the marketing asset, is it better for Total perhaps to take this opportunity to scale down in the France marketing and monetize the asset? The second question is, Mozambique. I think you're still talking about two thousand and twenty-nine. Yes, everything is all set on the negotiation on the cost and everything, or that you still have hurdles before that is really a good set in stone, that right? Thank you. Okay. No, but I mean, first, you know, we made some JV. We sold some assets to Couche-Tard. We made a JV in Belgium, so we are learning a lot on this part of non-fuel sales. And we want to apply what we learned from this Belgian JV, including in France. No, we do not intend to divest our French marketing assets. To be clear, this is a strong position. We have 22%, 23% of market share. It's a profitable one. What we want to do is to continue to benefit of it by, again, accelerating this non-fuel sales, and we are learning, and we see some position, but it's a strong position that we value. Honestly, being what we are in France, with the size of the company, will be difficult to not manage or sell this business, including for French consumers. The Mozambique. No, I think we've to be clear, and I think I commented it in last call in end of July. On the contractor side, everything has been said, including the cost of the frozen period. It has an impact on the cost of the project. I think one of our peer partner mentioned $3.5-$4 billion. But this project remains profitable because there is a portfolio in particular of LNG sales, which is quite attractive, and so we are committed to the project. On the security side, there are some progress on the ground. You know that, Mozambique has an alliance with Rwanda on it. There is an election in Mozambique. A new president will come. I intend to visit Mozambique by the end of the month, myself, to meet him, to discuss about the way they intend, the new Mozambican authorities intend to maintain this alliance with Rwanda. And then we are working on the last piece in order to be able to restart the full projects, is the financing of the project. There was a. When we inherited the project from Anadarko, it was quite a big financing package. I think it was almost, Fourteen billion ... $14 billion. The different ECAs, as I would say, 70 of 80% of them have confirmed, after a due diligence, that they are committed to that, and we are waiting for three of them to confirm as well their commitment, because it's important. And some of them are in country, Western countries, where in between, I would say, the stance towards financing of LNG projects or oil and gas projects have moved, but all of them are telling us, repeating us, that they are committed by the contract they signed. So we are waiting for the green lights on this financing from these three credit agencies. I hope we'll get them soon, and as soon as all that is in place, we intend to restart the project. So the 2029 target, which is on one slide, is linked to restarting the project by, I would say, year-end 2024. So this is where we are today on this project. Let's go this way. Biraj, please. Hi, thanks for the presentation. Two questions. The first one is on the $2 billion of CapEx flex you talked about. Could you just articulate a little bit more on where, which divisions that would come from and how you think of - how we should think about that flexibility there? And then the second question is on dividend growth. You referred to the at least 5% in line with the shares bought back, but you're also putting forward a story around growing free cash flow and growing free cash flow potential. So going forward over the medium term, should we think about dividend growth at a minimum to be in line with the shares you bought back in the prior year? Is that a fair assumption? We've done it? As in going forward. Is that fair? Be clear, the board is quite clear that when we bought back, we intend to grow the year after the dividend, at least that what we bought back, in order to maintain at least constant, I would say, the billion dollars in terms of absolute amounts. We could decide, because we have a perspective of growth, to go beyond, like we've done with the 7%. So last two years, we grew it by 7% in euro. By the way, it was 8% in dollars, because we capture it by growth, part of the perspective of growth. You know, the board is confident about these figures. So there is a flow, I would say, which I'm repeating today and translating it for 2025. Then the board will appreciate. Again, normally, we take the decision by February board because we prepare the next AGM, and we did not accelerate today. We worked more in the preparatory work to this investors presentation. We spent more time on the buyback perspective because we knew that people were expecting from us to take some stance on it. So I think we have delivered to you a clear message on that. And again, on the dividend, yes, we are committed to that. So we don't intend to spare money, thanks to the buyback from the dividend amount. In fact, probably as we've done the last two years, we intend to grow it in absolute term. And the other question, the flexibility, sorry. Flexibility, you know, it's, of course, it's a different ways to look flexibility. I remind you that in 2020, when the COVID came, we found $4 billion of savings, you know, in the CapEx. So you have flexibilities. Of course, it could be some, I would say, short cycle projects, drilling infill wells, which could be deferred if we had to do it. We need to look to what is the impact and the choice between production and that. But again, I think that I don't see that as being immediately done. I said $50 per barrel, less than $50, because again, the balance sheet offers us a possibility to maintain our, I would say, our CapEx program. But one of the exercises which is done, to be clear, the way we work, each time we prepare a budget, and it will be done for 2025, the colleagues, they will come with a base program, which is based on the figures that I mentioned to you. And then each of them is supposed to identify what do we do at $50 per barrel or at $40 per barrel in terms of CapEx. So we'll have different options, and then we'll see which ones are, in our eyes, the most efficient ones. So it's coming from different, all the divisions are concerned by the point, and not only Nicolas, but everybody will be, will have to activate. But we have the flexibility. It's already, not for example, in 2025, part of the CapEx, organic CapEx, are FID. We did not yet have taken. You know, we have pre-FID CapEx in that program. So if we want to defer one by another six months or a year, we could do that. We have a growth, we have some flexibility. I think one of the comfort we have is that the depth of this portfolio is quite large, so we have optionalities, and, I, I prefer to be in a position to have more options than to be able to defer some of them if CapEx are not there, of if not to overstretch the company on the, than the contrary. So it's a better position from a CEO to have more choice than, being obliged to look for additional, reserves. We have that in the portfolio. Let's go in the middle. Giacomo? Thank you. Giacomo Romeo, Jefferies. If I look at slide 53, where you show your cumulative CFFO, you talked about this 60 billion on top of the existing dividend of excess cash flow generation. And you pointed out obviously the current rate of the buyback, assume it's 48 in that time frame. It's how do you think about distributing that extra cash flow? Biraj asked about growth in dividend. That's where actually how do you think about allocating between buyback and dividend? And in the past, you paid a special dividend. Is that? Would you consider that no longer on one of the options you'd be considering? Second question is thank you for the update on the U.S. listing. Or, in the past, you talked about thinking to move the primary listing in the U.S. Has that option completely dropped, or you will keep that as- I never said that. Okay. Don't believe always what the news press or an agency say. I never mentioned that. So, be clear, it has created some move. The project, as I said, is to transform ADRs into ordinary shares. If we can do it, but it's linking, in fact, the U.S., the French market and the U.S. market, so that the shares could circulate, that it's quite, it will improve the liquidity, but there is no idea at all to move any primary listing. Paris will remain the market to introduce shares, and we'll keep the quotation in, in, France. Okay? And we will remain, from, SEC regulatory point of view, a foreign private issuer. We have already, in fact, all the regulatory burden. Moving from, ADRs to ordinary shares does not change anything from a regulatory point of view. So that's why if we can improve the situation for US investors, it would be good. They could have access to ordinary shares and not only ADRs, which I understand when we make some discussions with them generate some friction, some additional costs, and some of them do not like this idea. So that's more the point. So again, it's transforming ADRs into ordinary shares. It's a technical project. It's not a giant political project. Not at all. Okay? On the distributions? On the distribution. First, special dividend, to be clear, we are very clear. We've done it, and it was really linked to an extraordinary situation of extra. I don't like to say that, but not extra profits, you know, extra cash flows. We made $48 billion of cash flows in 2022. Compared to today, it's around 30-35. It was, I would say, a situation, and so we decided to share this extraordinary situation through a special dividend. Don't consider it a normal instrument. You know, it's an extraordinary instrument, I would say, to extraordinary situation. Your math are good. I think my view is that we should work first on, as I said previously, as we grow the dividend quicker the last years than only the buyback. You should have not only a stable $1 billion per year of dividend, but it should grow. That's part of it. So if you go from 8x to $8 billion per year to $9 billion per year, you would consume part of it. On the buyback, I consider that $8 billion. I like the consistent policy to repeat, so for the time being, I don't see. If we really deliver first, again, be careful, it's an assumption that we remain at $80 for six years. It's just in Excel, but you see that, you know, and so my colleagues, they love Excel. They calculate with Excel. Life is a little more different than that. You could have more. I never seen the flat, even if we experience this for almost two years, one or two, eighty-two, eighty-three. So we have experience, but so it's just to give you an impact, size of the magnitude of what could be generated. It gives me confidence, but at this, as I said to you, we could easily, we could maintain the buybacks, and we could also grow the dividends. Okay? Let's go to you, Chris, that side. Yep. Thanks. Christopher Kuplent from Bank of America. ... Patrick, I've got a question that feels like a question I should ask over lunch, but I'm gonna put you on the spot. And it's regarding your macro consumption. You just mentioned 80 Brent for six years. You've attached to that $8 per BTU, and Stéphane, in your presentation, you also gave 60 and six. So maybe I wonder whether you could, A, comment a little bit about the dislocation we've seen this year in JKM TTF versus Brent, and how that's potentially impacted your view on Brent slopes as you continue to sign new contracts, as you've shown. And secondly, the more trickier question: Which one of those, 80 Brent or $8 TTF, do you think carries more or less upside risk? Upside risk? I'm not sure to understand the notion of upside risk. Which one of those do you think is more bullish? By the end of the decade, the $8 is more bullish than the $80, clearly. Because again, I'm facing the reality. I think that TTF could go down to $6. So my combination personally, I mean, with the board, was $80 Brent and $6 gas. It does not impact. You have this sensitivity for $2 per million BTU, it's $400 million of cash, so multiply by six year, it would make $3 billion. So it would not change fundamentally the cumulative free cash. But if to answer clearly, no, I think the. On the whole, again, we face a situation where the demand continues, and the investment is lower than before. And so on the gas, we'll have to manage these capacity waves. So I mean, I'm. And we experienced that in the past, and I think again, I'm not afraid because it will foster the demand, and I'm not afraid because as we decided with Stéphane, we move to the brand. The beauty is that you could ask me, "Why then do you have customers signing this type of contract? Why?" But because they experience what happened in 2022, 2023, and they are not sure again because some events could happen, you know? And in this world, we see some more disruption against supply than against demand. So that's why I think they sign. And yes, the slope, we have an impact. We have some guidelines on what we want to do, as it's also important, and Stéphane could complement, and he insisted in his presentation, it's not only for Brent, it's the capacity to arbitrage the optionality we have in this contract, which is important for us. So of course, you have an arbitrage, which is covering Asian with, I would say, a Brent formula, but what is the amount of optionalities you keep if you want to benefit from overall dislocation of the market? And I think that's why the teams are working on. On the first one, you wanted maybe Stéphane to comment on the dislocation that you observed. In fact, JKM has been higher than the +$1 became +$1.5-$2, I think. So there is more demand on this side. Maybe you want to comment it? No, what we see is that we went from a situation where Europe was clearly pulling all the market and the spread was in favor of Europe, and we saw which were closer to twenties and the market has rebalanced because fundamentally Europe is consuming less gas, and now China and India is consuming much more, and we see very interesting thing in India, actually. So that's one. Second, it's clear that the logistic issue in Panama and U.S. has not helped and has triggered an increase of the gap. Now, if you look at the forward curve, you see that the dislocation is diminishing in 2027, 2028. So all the markets fundamentally see what we see. And just last comment, the $8 gas is a TTF one, is not a JKM. So that means that, that's not 10% Brent slope, so it's a bit above. And we are clearly signing above. Okay. We go on this side, Lydia. Thank you. It's Lydia from Barclays, and I've got two questions, if I could. Patrick, you presented a really compelling story here. You've got 4% growth in energy production. We've got $80-110 billion of free cash flow. You could buy potentially back up to 30% of shares over that six-year period, and you've got an incredibly compelling team to kind of go through and execute that. So what worries you, if I put it that way, as to what actually bothers you and what do you spend most of your time thinking about? And then secondly, I think the phrase you used a few times was copy-paste, and how much in practice is that actually saving you? And are all contractors as open to it as, for example, your existing ones versus some of the new ones you're bringing in? The copy-paste has been what we've done, honestly. Suriname, we are able to sanction it one year after appraisal because we took a strong decision to convince our teams with Namita and Nicolas that if the design of SBM was good for our big, our nice friend, big friends next, I don't see why it should be not good for TotalEnergies. So I'm sometimes, you know, we know, I know I have the best engineers in the planet, but so we are very strong, and so make it as a difference, and it concluded that it was okay, so it accelerated. Of course, for the contractors, for the contractor himself, they see an economy of scale because it's an additional one, and we try to replicate it on Namibia with the difficulty of the gas, because if we have to have big gas machine handling 500 million scf per day instead of 200 or 300, of course, it changed the dimension. That's the limit of it. I think it's more time to market and being efficient and giving a chance to the contractor to benefit with us some economy scales than doing the different contracts. So I'm convinced on some topics it works. Petrobras is doing that. You know, we observe it in Brazil between the Sépia-2, Atapu-2, and all that. At the end, we have, by the way, two FPSOs. It's two for one. It's the same.... You know, it was we applied with Petrobras, and so if Petrobras can do it, I think we can do it as well on some topics. That's another point. Because we face an inflation in our, because, you know, at $80 per barrel, the service companies, contractors, they want their share of the cake. So we need to be to be creative if we want to manage this inflation. What worries me to do the most, or what worries me is, first, the world, honestly, the global world is strange. I mean, dislocation, rupture, very well. So I have experienced in 10 years of CEO some incredible events: the COVID, the Russian war. Now, we sort of. I know that unfortunately, again, Excel and this linear way to present the things will not happen, you know? I'm paid for that, so to be to look around and to say. The other part is we have a lot of things to execute. Part of it is operated, part of it is non-operated, so I think the spread. It's really being able to execute these projects and some of them are and I visit Suriname. I think for me, we are clearly Suriname. It's exactly the core of the company, deep offshore, operated. We have other projects onshore, which are more complex to execute because we face more difficulties with stakeholders, et cetera. That's, I think... And there, on our side, what we should do as the management is to be sure that we have the right person at the right place and that we have enough on the ground. So it's more execution of all that. Okay, I would say. But and then facing a world which clearly is becoming more complex for global companies because you see some fractures, and that could have impacts or some impacts on our indirectly on us. Okay. So I'm expecting the unexpected to be clear. Let's go, Jason, there. Yep. Thank you. Hey, thanks. Jason Gabelman from TD Cowen. A couple questions for me. First one, hopefully pretty simple. On the free cash flow growth of $10 billion, I'm wondering if that incorporates any decline in CapEx, because it looks like you have higher organic CapEx earlier and then lower later. And then what does that kind of imply for the free cash flow trend, over that period? Is it more modest early on and then greater longer out? And then my other question is just thinking about buybacks moving forward, and you had historically talked about a net gearing target. It used to be 20%, I think earlier this year or last year, it was down to 10%. Now it's kind of gone away. Is that still a relevant metric as you consider how you manage your balance sheet and distribute cash to shareholders? Thanks. No, we normalize it. I mean, to be clear, we gave you a range of CapEx of 16-18. So we took 17 for the calculations. So if you consider compared to 2024, where we are around 17-18, there is not much impacts on the free cash from the CapEx. You have maybe EUR 500 million, EUR 1 billion, let's say, maximum. And it's why we say more than 10. Ten you can consider ten as without any positive impact on the CapEx decrease, just to be transparent on this one. Yeah, I mean, no, we cannot give you. I mean, it's more complex than that, the reality. There is some flexibility in the balance sheet. If we are using. If we told, I answer to you it's lower than $70, that means that, I let you make your model, but you will see that, of course, if I'm continuing to buy back $8 billion at $65, that means that, the gearing will go up. It's not 10%, obviously, it's not 20%. It's in between, somewhere. I think, again, things are not happening linearly, unfortunately, in the world. So you can, if suddenly you have a war on the oil price and you see a crash like in 2020, where do we go? You know, that's. But in 2020, we demonstrated you by keeping the dividend intact and, managing the CapEx downwards, but we accepted the gearing to go up above 20%. You know, we accept it because we think, because we are also convinced this type of situation do not last for long. You know, it's a matter of. And we are in much more comfortable situation with a gearing of 10%. So yes, we will accept to have a higher gearing in order to do it, but it's a debate. Again, we find, I think, a positive message to you investors about the buyback, which is we maintain the $2 billion per quarter at reasonable market conditions. So with that, you do your math. We can maybe take questions from the online, maybe? Oh, you choose. You are the master of ceremony, media, Mano. Okay. So Matt from JP Morgan, please ask your questions. Thanks, everybody, for taking the questions. Two quick ones, if I could please. First, just following up on the previous comments on cash return. You've emphasized keeping the distribution of cash flow above 40% of CFFO. It does feel to me, though, that there's a greater propensity to distribute higher than 40% and use the sort of mid-forties, for example, if it's necessary, than was the case in the past. I wonder if that reflects the successful progress in de-risking the multi-energy growth proposition over the course of the last one to two years, and if you could comment on that. And then secondly, on LNG... One of the hallmarks of the business in recent years has been, I think, the ability to flexibly deliver between regions, and particularly between Europe and Asia. You showed, I think, on slide 47, increasing contracting into Asia over the coming years. How do you think about the best and appropriate balance between increasing that contractual commitment into Asia versus maintaining the optimization flex between regions? Thank you. Okay. No, be clear. You notice that you make the math $8 billion of buybacks commitment like we've done with our dividends at $80 per barrel, you are more at 45% than 40%. But the 40% guidance is through cycles, which means that it will apply also at $50 per barrel. And at $50 per barrel, to keep 40%, make the math, you will see that we need to make some buybacks as well. So it's the guidance is through cycles, at least, yeah. So there is no change. It's true that at $80 per barrel, this year will be, and again, it'll be, you're more around 45-46% than around 40%. The commitment is full cycle, that means that we will keep this 40% guidance at $40 at $50 as well. So we don't change it at $80, even if in the fact, the reality is what I just told you, it's true that at $80, it's more 45% plus than 40%. You can answer, Stéphane, about keeping your optimization. Yes, the truth is that it doesn't lower my capacity to arbitrage and to optimize, because typically I take a US cargo, I sell it on the Brent index in Asia, nothing prevent me to buy back the LNG I need to make my sale in Asia based on JKM, and to send my cargo in Europe to sell it on the TTF. So it's not because I'm selling in Asia on a Brent index, that I have lowered my capacity to arbitrage JKM, TTF. I could even argue that actually I'm extending my capacity of arbitrage between Brent and JKM. The only thing that I need is the fleet and the regas, because I need to be able to go in Europe when I want to go in Europe, and the good thing is that I've got the largest regas capacity today in Europe that I'm using for that. The regas we have, the fleet we should increase. Clearly, there is no So the point is that today we have the regas, no problem. The fleet, we need to dimension the fleet, but it was in our plan according to the volumes. Yes. So we cannot have more volumes without a larger fleet. Well. So, we are just trying to understand when is it the best to commit on the fleet, and so there is a monitoring by our shipping SVP, who is coming to us regularly to ask for more LNG tankers. But we know that we have to dimension the fleet according to the volume. Okay, let's go Alastair now. Can I ask two things? Well, on the integrated power, can maybe probably Stéphane, can you talk about the embedded exposure to power prices? So, you know, you, we're using $8 gas. If you know, if we come down to $6 and prices are set by the marginal cost of fossil fuels, you know, what does that do to the $5 billion of cash flow? And then secondly, I'm gonna direct it to the screen, if Helle's still there. I'm sort of interested in observations on China oil demand this year, given the high EV sales. As someone on the ground, you know, what is she seeing? That perspective will be useful. Not yet. He's still alive? Yes. He's still not yet. Still alive. I don't know what time is it in Tokyo. You know, I'm a little lost today, so it's quite probably quite late. But, so, I will give the floor first to Stéphane, explaining how it works in the integration going from eight to six. Yeah, so it's a bit difficult question because actually you don't have one power price. You have plenty of power prices depending on which market you are looking to. That's one. And second, on the EUR 5 billion cash flow, part is coming from renewable, which is exposed for the merchant part to the wholesale market price, and part is coming from the flexible asset, typically the CCGT, which is more the difference between the power price and the gas price. So it's not because power increase. If power increase because of gas, at the end of the day, the CCGT is still making the same thing. So you can't expect to have the same sensibility in the same way we talk about crude. That doesn't work. Having said so, today, our sensitivity is limited because clearly we still have a merchant exposure that is not that high for the renewable part. On CCGT, that's more the case, and by 2030, we are probably talking on the $5 billion, $1-$2.5 billion of flexibility, depending on which index you will look at. So it will be sensitive to price, that's all. Other questions? One thing which, in the integration, just to comment on it, when the gas price is going down, the electricity price normally is going down, and suddenly you have a... ... Yeah, A parachute effect on all your consumer business that we experience today. In 2024, we make quite a lot of money in the electricity with the consumer, consumer portfolio in France. Because you price, you are pricing, you benefit from the fact that you are pricing your electricity with a price risk premium in advance. Yeah. So that's why we discover that in fact, we have a nice chart, and we'll come back one day with you with figures. In fact, the integration helps us to benefit from one part of the portfolio. If a higher gas price is not good for CCGT, but it's good for my integration upstream, et cetera. So you can look at it, and honestly, the more I'm looking to this integrated, this electricity business, the more I see some good integration with if you are along the value chain with our gas business and not only renewables business. Okay. Okay, so Irene. Hello. Hello, is there? China. Speak about China and China's demand. Just a couple of comments around the question. Number one, the realities, of course, is that China is leading in terms of, I would say, EV sales because of the scale of the country. But remember that when China talks about EV, effectively, it's new energy vehicles, and there are plenty of hybrids also. So it's not pure battery EV cars that, you know, are penetrating in the Chinese market. And I would say that at this stage, the broader question on the oil demand in China, knowing that the new cars are, you know, penetrating the fleet, and that's embedded in all the forecasts. I think the bigger question really is the economic situation in China, and you know, the question if China will do 5% of our GDP growth this year, will do less, and what the growth will be for next year. So, let's wait and see what comes out of all the you know, the new measures that were just decided by the Chinese government to stimulate domestic demand. I think that is actually the variable that will be the most important for oil demand in the coming years, short term. If I try to put it in perspective. You know, in the increase of oil demand, China was represented, let's say, out of one billion barrels of oil per day, 600,000 barrels of oil per day, 60%. We should accept that it will diminish, and that the 600,000 barrels per day coming increase in demand from China maybe will be 300, 400 thousand barrels per day, in my perspective. So there will be some relays, and a country like India obviously is far from consuming as much oil as China per capita. But we should, I think, in this demand part of oil, that's why somewhere in our curve, we continue a growth, but the growth is not the same pace. Because for me, I'm integrating the fact that we have, in fact, the year two thousand, two thousand and twenty were eras where the oil demand was completely driven by the Chinese growth. And again, an average of 60% of growth was coming from China. We are entering into a new era where clearly, because the Chinese economy itself is not relying on the same, I would say, dynamics, the oil demand from China will not grow at 600,000 barrels per day per year, but more 300,000-400,000 barrels. We must integrate it, and it's not only, it's not the EV only. It's not the EV. The EV is part of it. It's not that. It's more, again, the fundamentals, the way the growth of China is built. They have twenty extraordinary years of, I would say, huge growth, 8%, 7-8% per year. We are more entering into 4-5% per year, so it has an impact on the growing demand. That's... If I took some perspective on the way I'm looking at it, and for me, it's one of the, again, key factors where this curve is beginning to plateau to something like, I don't know, six million barrels of oil per day or liquids per day, rather than continuing to go quicker. Okay, Irene, there, please. Thank you. Irene Himona at Bernstein. I had two questions, please. First on refining, second on LNG. Refining, you've demonstrated you've done a lot of work to on the portfolio, cutting costs, energy efficiencies, and you assume a $35 per ton margin in the plan. What is the refining portfolio's average break even, whether cash or PNL break even margin? And can you share your views on the outlook for that industry out to 2030? On LNG, you have this very material, 50% growth in your portfolio to 2030. Can you say how much of that is already contracted, to third parties, so not, not to your own portfolio, and what is your aspiration for that by 2030, please? So I think, Bernard, what is it, 25? Twenty-five, yes. $25 per ton. $25 per ton. Knowing that generally, when we rationalize the portfolio, we eliminate the worst ones. We have a certain economic logic, you know? When we avoid to stop the right ones. So in fact, it's a way to manage your break-even. You know, by the way, if we manage to get this return on capital employed in refining and chemicals in 2012, whether was it charged, I said to my colleagues, Bernard, "Okay, there is one way to have a better profitability is to get rid of all these losses," you know? And they get before to speak about volumes and expanding, so that's part of that. So today it's down, but we still have, so when we analyze the situation. The outlook for the industry, you know, I've never been a big fan of investments in refining, to be honest. I think you have too many refineries. Clearly, they have built a lot on the eastern part of Eastern Hemisphere. I would say in China, a huge amount of refineries coming on stream, because they did not stopped the teapots. You know, I remember when I discovered that word, there was a nice story. Don't worry, they expand new super modern, big refineries, and we will stop, shut down the teapots in for this, are the old refineries. In fact, nothing has been done just because they are provincial tools, the jobs and that, governors in province, even in China, don't want to stop, and so they are there, and so you have extra capacities. India has built as well. Korea has quite a lot of large refining capacity, which was mainly dedicated to the Chinese market, but then Chinese market, their own refineries, so India refining is also. You have all this part of the world, and because it's linked to, you know, governments, security of supply, they want the refineries, whatever, you don't look the market. Then you have some impacts. In Europe, there were four, five years, three, four years of very good margins, so all the work which was done from 2012 to 2018, I would say, which was rationalizing capacities, including we've done it and we continue with Grandpuits in 2020, but we are done. Not many have done continue, was stopped. Again, we are facing the reality. The reality is that you have a declining market, and despite the rationalization, job has to be done again. Who will do it? We'll see. Some companies have done, maybe, some others. And then you have the position on the US part. We've one difficulty today, which is the impact of these Russian products, which are dislocating somewhere the market, you know? And because it's quite clear today that the Russian products are still continuing to flow in South America, in some regions, and it has an impact on the. For example, US refiners are sending today products to Europe, which does not help our situation. So, so it but yes, it has to be rationalized. On our side, you know, we know what we have done. We have shut down one refinery or transforming, not shut down, transforming to biofuels, one refinery every five years, more or less. So we need to continue to adapt ourselves, knowing that we are at a point where, in fact, we have three or four nice refineries in Europe. We consider being well positioned in terms of in the competition, so we don't intend these ones to suddenly to rationalize them. So that's where we are. So I expect, I will observe what the other will do, but it's a little like energy. You know, it's good to have sometimes some low margins in order to force some players to go to take decisions. We have done part of a job. We will also look to what the others will do and not only taking the burden on us. If we do it on our side, it's because we see part an opportunity again, like it was explained, to transform a refinery in biorefinery, knowing that on the soft part, if I can produce it by co-processing, is more efficient to make co-processing than to have even if a brownfield. So we need to. But there is this product, which is the HVO, producing HVO in order to co-process this is maybe a nice way. So we are more looking to this evolution as is it the right time to add, I would say, biofuels production capacities in our portfolio as a transition opportunity. But I think the second question you can answer, Stéphane, because I think you've done the math, no? Yes, um- 50% of the growth already contracted. If I'm looking to your, - Z- ... your chart, you have five million tons remaining, no? What, Yeah, so if I understand correctly the question, there is the part I'm offtaking myself on that I plan to resell and then explain what we plan to do. So by 2030, I still have, as Patrick mentioned, a few million ton to sell, so as to be fully contracted. By 2028, I'm fully contracted. And if I got your question correctly, your question is about the volume of the projects that are not sold to that I'm not offtaking myself, but I sold to third party. And in that case, for all the project normally is fully contracted at the time of FID. If I take Rio Grande, that was the case. Costa Azul, that was the case. The only case I know where it's not fully yet done is Qatar Energy on, the North Field expansion, but where they will clearly do it- No, but it will be done. So- - because the Qatari are doing it, themselves, their policy, Kuwait- Yes ... recently. So Qatar- So we are not- We are not- We are not really concerned by that. No, I'm not concerned by that. No, normally, it's not a problem, but... So let's take Kim Fustier, who's waiting online. Kim? Yeah. Hi, good afternoon. Thanks for taking my questions. So- ... Unfortunately, Kim, we lost you just at the beginning of your question. Let's take. Another one in the room. Kim will be back. Lucas, maybe. Yeah. Thanks very much, Patrick, and I think I need to talk to you about my electricity bill in France, by the way, given your previous comments, I'm gonna be looking for a rebate. You were very generous a year ago. No, I- I mean... We gave a lot of rebates last year. This year, we keep the money. They don't take it because it's part of here. Yeah. But I'm protected by a big company in France, which is shouting more than us, you know, on the electricity part. So, no, I should have. I will send you the bill for the previous year, you know. Okay. Okay. Maybe we'll just move on then. Listen, three questions. One, I presume I'm not gonna get an answer to, which I guess is to Nicolas. Tamboti, any idea of what the... Are you happy to talk about what the pre-drill estimate is? Oof! It's big. Well, define big. Elephant. Oh, okay. It's a $1 billion target, all that. All right, fine. Billion barrels. But you know optimism, you know. You know, explorers, when you are in a prolific basin, suddenly they see, so it's, it's, it's big. Yeah. Okay, thank you. More than I expected to get. Secondly- Yeah ... just coming back to Michele's opening- We are very transparent to you, Lucas, you know. Just coming back to Michele's opening question and your comments on the U.K., just remind me, what is the CapEx spend in the U.K. at the present time? And the third question, while you're thinking about that, was, I wonder if you could talk a little bit about the agreement with Air France and just how you go about pricing SAF with an... Or how you've approached pricing SAF with an airline, you know, given what's been happening to, you know, jet diesel prices, et cetera, et cetera, and the challenges obviously around feedstock, but just making a margin. If you could talk around the structure of the contract? No, I'm not gonna describe the structure itself, but it's very clear we have every year, at the end of the year, we meet, and we find an agreement. That's it. These airline companies are short term. Yes. They don't like to commit themselves. It's a one-year contract. You have a framework contract with the volumes, so we are committed to bring the volumes, because today they are looking for volumes. And then we... It's a short, it's one-year contract permanently. Honestly, that's why historically, the airline business has never been a very good, very profitable business, you know. When I was looking to my margin per tonne of CO2, I can tell you the airline business is tough ones. The SAF is different because suddenly they are obliged to buy. There is, on the SAF market, more demand than supply for the time being. Yes. We need to be careful with the co-processing story, you know, about it. So it's putting them in a different situation, but it's quite, so it's commercial. There is no commitment on this one. And the U.K.? In the U.K., I don't know. You have two hundred- This is your chance for some leverage. $200 million? What? $200 million. $200 million. $200. Mainly in field drilling, but you know, many wells, but it's not... But we can go down, huh? Yeah. No, honestly, today, for example, exploration in the UK, I asked my team to stop. Because with this political landscape, you are not even sure that even if you find something, you will be able to develop it, so that's part of the problem. So... But as I said to the Prime, to your Prime Minister, UK Prime Minister, at that meeting, you know, when I read this, this summer that there was a Norwegian company considering to bring a FSRU in Scotland, I told him some things may be wrong because you have gas there. So let's come back to security of supply discussions. Maybe, they are not afraid by Norwegian companies, but if suddenly you have a country which has natural gas resource and which is importing LNG... Did they hear you? I don't know. I don't know. Thank you. We have a question from Henri there. Henri is there in front. Did you get, Kim back or not? Kim, next. Next one? Yes. Okay, Henri. Henri Patricot from UBS. Thank you for the presentation. I want to come back to the macro outlook and US gas prices. Could you share your view on what is the evolution up to 2030? Sure. And on a related note, we've seen two transactions in U.S. onshore gas. Is this an area where you'd like to build further your position, or are you happy with what you have now? Yeah, yeah. We are making a string of pearls strategy where you try to capture one by one, not giant transactions, but it's the right time because the area is low, so it's countercyclical, so we have good opportunities. As you notice, both have a common point. By the way, it was the same company to which we bought and we farm into leases, because it's well located, our properties not far from Rio Grande. I don't know. The U.S. gas price, fundamentally, you have big gas reserves, associated gas, so the U.S. and Europe should remain low. But you could have a scenario which is not the best one for us. That's why you need to protect. You have oil price going down, your shale oil producer begin to slow down all of their drilling, less associated gas. At the same time, you have more export for LNG, and then what we experience in 2022, suddenly the prices go up. So that's possible. I mean, it's not my favorite scenario, to be honest, but we have to face it... So that's why I think for us, the strategy is to try to protect by growing our own integration. That's the beauty of integration, because then if we are more integrated, but we will benefit to our higher Henry Hub. It's not the main scenario. Our main scenario when my colleagues which are in charge of strategy, they say, "Why do you do that?" Because you know, you have huge gas resource in the U.S. But this point where you see more and more gas LNG exports could have, including some bottlenecks into the system, the network, gas networks that we experience, which could create some hike in the Henry Hub. Maybe it's only a short period, some few period, but it's possible. So I think the best is try to protect us. Otherwise, yes, we are in the view that $2.5-$3 per million BTU. We use $3 per million BTU is a good, is normally the base assumption for Henry Hub, I would say. Like we say, as I answered before to someone of you about what is your base assumption. But you have what is the base in Excel, again, the linear part, and you have the reality, which gives me more. And you need to protect yourself, yourself. It's our duty, benefit of integration, to protect on what could be a nonlinear scenario or the main scenarios, I would say. Maybe Kim, we try Kim again? Yes, Kim? Hello again, and apologies about the technical issues. My first question was on integrated LNG cash flow and the trading and optimization environment. Earlier this year, you guided to almost $7 billion of cash flow from integrated LNG this year at $10 gas. And your slide today seems to imply more like $5 billion of cash flow on the same macro assumptions. Could you talk about where the delta comes from and on trading and optimization conditions in LNG and pipeline gas? Secondly, on costs in upstream, you've talked today about mitigating cost inflation. The cost curve you've shown- Okay, we got the first. So, Could you say where the increases in costs have come from? Sorry, Kim, you were cut. So we captured the first question about LNG cash flow, but we did not capture the second question. Okay, cost increase coming from upstream. Okay. I have somebody writing to me what they heard, so that's why. What are the cost increase coming from in the upstream, if I understood correctly, the second question. So the first one, well, it's true that somewhere we guided we were optimistic. It's not really the LNG business. The LNG is more or less as planned. In fact, where we have a big difference is the gas trading, and just because when I'm visiting my gas traders, they are completely depressed because there is no volatility or very low volatility. And in fact, you know, you make results in. So in fact, they were quite positive when we established all the budgets because they were on the trend of the volatility we are experiencing. Not the absolute level, it's not the absolute level, it's more the volatility, which I would say generates some positions, and they can benefit of it. So they were thinking that the volatility could remain, and in fact, if I understand correctly, when I visited them in Geneva, they are not very happy because when I ask them the same question, don't worry, Kim, difficult to answer to me, but so that's lack of volatility. But it's true that previous winter was mild, and we end up with stock very high at the end of the winter, which means that volatility is completely dropped because the market was supplied. So it's a gas trading, it's not the LNG itself. So we'll see. Cost increase coming from in upstream, I think, every... In particular, for me, what I observe in the projects, but you can elaborate, is that, is on the subsea system and, all these parts, subsea SPS is difficult to manage because less players, I think, no? Yeah, indeed. So subsea, subsea equipment, marine installation vessels, which is related to subsea equipment installation for deep sea. On drilling rigs as well. Drilling rigs, you know, in 2020, we are $200-$250 a day. Today, $400-$450. Okay. In fact, fundamentally, it is a result of, I would say, a situation in which you have less players. So it's why one of the axes is to go to more Asian contractors to open the game, because in fact, on the western part, which were our traditional, I would say, suppliers, we face the same two or three companies when we speak about subsea equipment, you know, so they are in a stronger position. Supply and demand. They were in a bad position before, today they are in a stronger position. Questions in the room? Yes, Jean-Luc. Jean Cromer at CIC. You mentioned at the beginning of your presentation, natural decline of 4%. One of your competitors in its outlook has recently increased their estimate of decline rate to as high as 15%, as I believe, explaining that as there are more and more unconventional developments, the decline rate is increasing. Do you see that happening in the global oil production, and do you see that happening in your portfolio? What are the implications in terms of- ... capital expenditure you need to stay flat. But it's not for TotalEnergies, it's a global average assumption. We could say four. The remark is completely true. In fact, the more you put unconventional in your global production, the more you have this unconventional decline rate is much higher. That's true. But at the same time, at $80 per barrel, you have more people working on inferior wells and trying to fight the decline. So at $80 per barrel, I see more. I see the fact that we, because it's short cycle CapEx, it's easier to invest, so it fights against the decline, I would say. But do you see more? And it's back fundamentally, one of the unknowns for me is how long is this growth coming from the shale oil in the U.S.? I would say there is, for me, a big question mark. How long does this remain at this pace? Because we see a lot of cons-- I mean, restructuring, even mergers there. We see, the growth we have today is more coming from the fact that they have, they had a lot of, I would say, wells which were drilled, they have to, to connect, etcetera. All the inventories of wells, which they stopped because of the COVID, which came today on stream. Do they really invest? It's more brownfield than connection rather than, new large projects, in my view. Plus, all these mergers, all these synergies. So maybe the growth coming from there will not be as aggressive as before. The natural decline outlook, yeah, 4% is probably, you are right, but I didn't want to exaggerate, to justify that we need to continue to invest in greenfield fields. The 4% is probably a low range of the decline. I could have put 5% and easily. But then what is also true in the trends is that we have observed another point where I think I'm bullish on the oil price, is because what you observe is that you have a trend, the reserve life of the industry has diminished. Not for TotalEnergies, but when I observe the global world or the old world, we are around thirty, forty years. We are today divided 20 years, I think, because more and more short cycles, US share, which have a low, lower, a lower reserve life. That makes me nervous if the demand continue to grow, or nervous, no, positive, bullish, because it's a demand. So I'm not nervous at all, by the way. Consumers will be not happy, but I prefer to be that efficient. So when you see the demand continue to grow contrary to what people think that we plateau, etcetera, and you have this shorter global, global reserve life of the industry, 20 years, we could face really an issue of to supply all that. So the acceleration of the short cycle in the mix from this perspective is not giving you a full security of supply globally on the oil side. Okay, any last questions? One, two, three. So thank you. I think that is good. We just skip the cocktail, we go straight to the meal, to the lunch. I think it's better. No, sorry, we have been a little longer on our side than expected, but it's always like that. We like. You know, there was a huge amount of work behind all these presentations, so thank you to my colleagues. I think we tried to share what we think are some insights in the way where business is run in TotalEnergies. Thank you, by the way, for your listening, but I think also we had a good session of Q&A. So it's time to close, and again thank you for your attendance, and I hope we convince you that investing in TotalEnergies is a good investment. So we'll see, and I invite people in New York to join us to the lunch straight away. Thank you!