Romain, it's time, whenever you're ready. Good morning, good afternoon, or good evening, wherever you are. We are delighted to welcome you to TotalEnergies Strategy and Outlook Presentation 2023. We are today in the heart of New York at the 102nd floor of the One World Trade Center in Manhattan. You can also follow us on our website, totalenergies.com. The program today, we'll have first the strategy and outlook presentation for a bit more than one hour with several speakers, including Patrick, of course. Then we'll have a comprehensive Q&A session, where you will be able to ask questions from the room, and we will have also the possibility for people who are not able to join today to ask audio questions. After the Q&A, we'll have the cocktail and lunch around 12 P.M. Without further delay, I invite Namita Shah, President, OneTech, to come on stage to launch the meeting with a safety point. Namita? Thank you very much. Hello, everybody. So as you know, we always start our our meetings with a safety moment. And today I'm going to talk to you in our safety moment about how we use artificial intelligence to improve safety in our drilling operations. So just to give you a little bit of context, when we drill, we enter into a reservoir that is under pressure, and in order to control and to have safe operations, we need to ensure that no oil and gas from the reservoir enters the well during the drilling operation. When small amounts of oil and gas do enter the reservoir, this is what our drillers call a kick, and we have a number of processes and procedures, both technical and human safety barriers, in order to control these situations. Clearly, what that means is, the earlier we know that we have a kick, we are able to control it. And so as a result, our teams decided to look at the history of all the kicks that we had had in the company over the past 25 years. So as an example, you'll see between 2015 and 2021, we had 19 kicks on our operated conventional drilling operations. We looked at the history to see if we could identify critical parameters and anomalies in these critical parameters that occurred before we experienced the kick. We defined, we found the parameters, we defined the anomalies, and then we fed all this information into an artificial intelligence tool. The tool learned to identify these parameters and to identify the anomalies. We tested this for the first time at the end of 2019 on a live well. The slide that you see over here on with the information that you see on the right-hand side of the slide is basically the first time this tool actually identified the anomalies and gave an alarm of possible kick, and a kick did indeed arrive a few hours later. Over time, we have vastly improved the tool. We get alarms very early in the process, and as you can see, it has been deployed across all our conventional drilling operations. And in 2022 to 2023, it generated 31 kicks, but we were able to ensure that we took all the precautions necessary and control, so we did not actually experience any kicks in those drilling operations. So we are now going to be training this tool further to look into more complex wells and more complex reservoirs to continue to help us to manage this type of risk. Now we'll go into the heart of the presentation for today, with, of course, a point on our safety performance in 2023. As you know, safety is a core value for the company. Work always on two key pillars. One is occupational safety, and the other is the prevention of major risk, very specifically the prevention and looking into technological risks. As you can see on the, the left-hand side, or my left-hand side, your right-hand side of the slide, we have worked a lot on occupational safety, and you can see that our numbers that we use to measure our performance on total recordable injury rate versus, our peers, has vastly improved. However, we have lost 2 people this year. We have lost, Johnson in the Refining and Chemicals branch, who was 55 years old and, married and had children, and Isidore in the Marketing and Services branch, who was 63 years old, was also married and had children. Of course, for us, it is extremely important that we continue to work towards ensuring that we lose absolutely no one during the course of our operations. We also work on major risk, and this year we have decided to everybody in the company into thinking about major risk and technological risk. As you know, safety is a continuous learning process and a continuous way of reminding people to think about the same things over and over again differently. And so we have launched a two-year campaign on technological risk this year. But as you can see on the slide, we have always worked on major risk, and, a few years ago, we decided to actually monitor and then actively reduce the number of losses of containment. So simply put, leaks of a certain, certain size, that we wanted to ensure that we reduced to reduce of course, the impact on the environment and on our asset. You can see that over the past five years, we have reduced the number of these events by over 50. Just an example, the kind of work that we are doing to ensure that we do the best absolutely that we can in terms of safety for our people, for the environment, for our assets. With that, let me now hand over to Claire for the next part of the presentation. Thank you. Thanks, Namita. Good morning, good afternoon to all of you. Thank you for that. Energy market transition is absolutely the kind of summary of what I'm going to say very briefly this morning. Our market environment is good, and you're going to hear that we have a great deal of projects. Bearing in mind that, as always, our strategy is driven by market fundamentals. We never forget that energy, the commodity market, and in a commodity market, you need to be sure that you understand what you're going to buy. So let's therefore go over once again, the market fundamentals as we see them. One of the key aspects of future energy demand is the growth that will be coming out of the emerging markets, the so-called Global South. 5 billion people today, excluding China, 7 billion people tomorrow. These people, they need much more and much better energy to be lifted out of poverty. We, in the richer countries, have to keep that in mind as we continue to push for and advance the energy transition. These aspirations of the so-called Global South are factored into the high-level market drivers that we remind you right here on the chart. We concern our three core markets, oil, which is the number one energy today globally, natural gas, a key energy for the transition, and power that will eventually, some point in time, take over from oil as being the number one energy in total final production. On oil, demand is pushed up by growing populations and higher living standards. This is true, notwithstanding the continued innovation efforts to substitute oil wherever it can be done, and what's going on in the electrification of passenger cars is a good example of that. Biofuel demand is essentially driven by mandates here and there in the world, but the overall opportunity is capped because of feedstock limitation. Biofuels are still very far from prime time. Regarding gas, the growth is coming from LNG, and we believe that LNG remains absolutely critical all through the transition. It is key also to build this new lower carbon energy system that we are working on, both for fault to back up coal and to implement, implement renewable. Low carbon gases are set to pick up over time. Biogas is today not much more than a profitable niche. And finally, power. Growing demand on a global scale is accelerated by the net zero policies of the richer countries. The increased penetration of renewables means that it's not going to be trivial to deliver what the customer ultimately wants, which is clean, firm power. And now, a quick word on the shorter term trends for each of these three markets. On oil, I'm sure that you all picked up on the latest report from the IEA, saying that demand will grow through the decade. Guess what? We agree with the IEA when they say that, and we show here their own forecast for rising oil demands to 106 million barrels per day in 2020. Unlike what we heard here and there in the past, including from some senior industry executives, oil demand did not peak back in 2019. As a matter of fact, it reached an all-time high in June this year. Of course, that's remarkable, given that the overall macro picture is somewhat mixed, and it's entirely linked to the long-term drivers that we just spoke about, demand in emerging markets. Supply, on the other hand, remains constrained, with two notable factors that we're listing here, is the OPEC plus policy led by Saudi, showing a clear intent to push the oil prices through volume cuts. And secondly, early signs that, U.S. shale will not be able to grow forever due to, critical discipline, slowing productivity gains, higher returns to investors, and sometimes simply also the lack of skilled labor. And all these elements combined create a supportive outlook for oil... to LNG. What you see here to the left is our internal analysis of the evolution of supply and demand until 2030. We expect demand to grow at around 5% per annum between now and 2030. LNG demand is known to vary both with weather and with prices, so this 5% is not necessarily going to be linear. That being said, the bulk of the growth will come from Asia, which has been competing with Europe for available supplies ever since the onset of the war in Ukraine. Bear in mind that Asia's level of demand of LNG is still below what it was in 2021, because Europe has been taking share and continues to grow above global market in 2023. So all in all, we're bullish on LNG demand. Supply, on the other hand, is going to be constrained, as the chart shows, until 2026, 2027. New LNG projects, coming mostly out of the U.S. and Qatar, will only come on stream in the 2026-2028 time frame. Because of the current tight market conditions right now, any supply disruptions anywhere in the world linked to port measures, linked to operational hiccups or strikes down under, all these unforeseen events create volatility and price spikes. As long as the market is short, meaning, as you can see on the chart, over the next 3-4 years, price environment for LNG is going to be supportive. After that, the availability of new and more supply will trigger a further uptick in demand. Just a last word on power. What's striking on power markets is that at the macro level, there are a lot of similarities with the oil and gas markets, meaning growing demand and tensions on supply. Power markets are increasing at a brisk pace of around 3% per annum until the end of the decade. This is triggered by the electrification of final energy consumption in the richer countries, net zero ambitions, and by increased populations in emerging markets, as mentioned earlier. And, well, in front of this growing demand, power supply is constrained, with lots of tension on power networks around the world due to aging infrastructure, permitting delays, supply chain disruptions, and also sometimes extreme weather events. Another point is that the ongoing decarbonization effort of power will make power systems much more complex to manage due to the massive arrival of these intermittent renewables separately. Dispatchable generation, balancing, storage, remuneration of standby capacity, all these elements are therefore going to be needed to ensure proper network management, rebalancing, and availability. Overall, this creates supportive price trends for power, too, and attractive investment opportunities for us, as you're going to hear a little later. Before that, Patrick, I hand over to you. Thank you, Namita and Helle, to have introduced the safety of the company and the landscape of the energy markets in which we drive our strategy. I will today, because you will have no surprise about the strategy, we consider that in these energy markets, our strategy, which is fundamentally driven by demand, and Helle explained to you why the transition are fundamentally supportive for energy markets and prices. We consider our strategy, which is a balanced strategy between two pillars, of oil and gas on one side, the energy of today, as the demand continues to grow, and bring the future with transition strategy, by offering profitable, integrated power segment, well adapted, and will be a nice way to grow value and to offer attractive return to shareholders. So, you will see in 12 slides, summarize the headlines of this strategy, and then, Nicolas will speak about oil and gas, and Stéphane will speak about integrated power before I come back to final conclusion, to give you the headlines of, the guidance we want to give to the company, we give to the company, to our investors, for distribution to shareholders. As I just said, there are two pillars in our strategy. One, which is our, we say, DNA, which is oil and gas, in which, we continue to invest, continue to grow, and I will come back on it. We refocused our portfolio on some fundamental, fundamental, I would say, characteristics, which is low cost, in order to be resilient to cycles, in order to deliver the value, lower cost, low break even, and also, of course, low emissions, because our first duty as an oil and gas producer is to slash down the, greenhouse gas emissions linked to our operations. We have developed, and we'll come back on it during this presentation, a rich upstream project portfolio, which will, feed optional growth. First, we have a core, also, focus on LNG for development. The reason were explained by-... We are, company has been positioned itself in, on the top three global energy integrated portfolio, with very, again, a strong energy project portfolio. This has allowed us to deliver in this type of price environment, high return on capital employed, 23, more than around 20%, with luckily, oil and gas extreme activity. Second pillar of the strategy of this transition strategy is to build a profitable segment called integrated power. All worlds are important, integration in particular, not only a matter of renewables, a matter of driving value from integration, integration between renewables, intermittent assets, and flexible assets, but also integration from the value chain. And, Stéphane and I will explain you how we will be net cash positive by 2028 in this segment, knowing that we invest $4 billion per year in order to make a sizable business. This strategy we've took now is a transition strategy that is fully compatible with a high level of profitability. I remind you that last year, in 2022, TotalEnergies offered the highest average capital return on capital employed among the majors, which demonstrates that you can be strong in oil and gas and your transition strategy while remaining profitable. This strategy is also, will also offer the company the highest production growth, energy production growth, in the coming until the end of the decade, with 4% energy production growth. First pillar is oil and gas. Oil and gas, as I said, will have a rich portfolio of projects. You have there a trajectory for the next five years that we intend to follow, which will offer to the company a growing oil and gas production of more than 2%, between 2%-3%. But with, of course, projects, oil projects, particular in the coming years, all the deep offshore projects in Brazil around Mero, but also in the Gulf of Mexico, and start up of our production in Iraq since August sixteenth, 2023, followed by projects in Uganda, Angola, and Suriname, on which we will come back. LNG, we have a large portfolio of projects in Qatar, Papua LNG, Mozambique, and Rio Grande LNG in Texas, to growth between 2025 and 2028. Globally, the key figure, at the same price deck, an increase of cash flow from operations from this oil and gas will be around $3 billion between 2023 and 2024. So what is this portfolio of projects? You have on this map, again, you know, all the major projects which we will intend to develop in the next five years. On the oil side is primarily deepwater, large giant fields in deepwater. Several projects in Brazil, around beyond the Mero that I mentioned, we have also coming to sanction Sépia and Atapu-2 on the licenses that we acquired end of 2021. And we have also in the Gulf of Mexico, I mentioned then, and then Suriname, which is a success of our exploration, where we will develop a 200,000 barrel per day project. Onshore, we have two large projects, one in Uganda, we have one in what we call GGIT, the Ratawi oil field in Iraq. You can see, at $60 per barrel, this project offer a return of 20%. The LNG projects at $8 per million BTU, European gas price, about 15% on average. $8 is quite lower than what we experience today, but it's comparable more or less to the $60 environment. As I mentioned, one things which has also is supportive of our growth in the oil and gas business, particularly on the oil side, has been our exploration success. I must today pay tribute to our exploration teams. You know, we have decided in 2015 to refocus the team on a, I would say, streamlining their budget, $800 million-$1 billion. Seems to be efficient. They have made some selective choices, and three of them, very recently, have been quite successful. In Suriname, first, we, which we entered end of 2019, after 15 wells, several discoveries, some of gas prone. But the good news is that we have today able to define quite a large project, 700 million barrel oil per day. Nicola will come back on it, on the eastern part of the block, 200,000 barrel per day. In Nigeria, this year and last season, we drilled conventional offshore, but it's very, I would say, time to market to this story will be short. It's a prolific, with the pure conventional, we indeed discovered around 100 million barrels of oil recoverable reserves, which can be linked to the offshore platforms in the coming years. In Namibia, we heard that you all expect news from Namibia. Don't believe everybody, you know, and people are in this world confounding the potential hydrocarbon in place and what you can produce. So it's just a factor in between the availability, the productivity per well, you know. So we are continuing. We had some positive news on Namibia. On the Venus discovery, which was, I remind you, discovered by what we call Venus-1X. We made a positive appraisal well, this year, Venus-1A. Made a test on Venus-1X. We just had the results, it's a positive flow test, means just correctly speaking. We will make, we have the next operation is to confirm this flow test on Venus 1A, which is just upcoming. So, with these wells, but there will be oil development there, on Venus. Size of it, exactly, has yet to be determined. We intend to continue to explore. You can see on this map, sort of prospects to the north of Venus, which is called Mangetti, which we'll be doing soon. So we go to the north there, and we intend as well, potentially, to make a last appraisal well on the north of Venus. One, to be very clear, there was one failure this year, what you call Nara. It was prospecting the west. This one appeared to be oil bearing. If you go to the west, graded, don't find oil. So don't... But it is positive, again, like Suriname, it's clear that it's a success, and that it will feed the future growth. So we need to continue to work, and, and, already we are beginning to think to, to the development, knowing that there is also gas, like always, like Suriname. But that's, similar to what we experienced sometimes in the pre-salt. And since it caught your attention, you can see, in the center of this slide, the two important parameters that we look at it, which we follow very carefully. The intensity of the Scope 1 and 2 of operations, in terms of kilograms of CO2 per barrel, was about 20-20 kilograms per barrel, which... Portfolio, kilograms per barrel. So you can see a large decrease, 40% of the CO2 intensity. We can produce oil and gas differently, and the methane is the same. We focused on it, since in 2010, 2020, we reduced by 50%. We intend to reduce our by 80% between 2020 and 2030. But we, there again, methane intensity in the industries, consider what we decided that our zero emission, like aiming for zero fatalities, you know, because we have the technologies to do it. So, we will lower our target, which was minus less than 0.2%, to less than 0.1%. Really, we, we will be able to, we are able to, make the gas. We believe that gas, after the transition... Are supportive to the price, and we are willing. Know as well, that we'll have some cycle in front of us. We should not repeat the mistake we've done in 2005 and 2015. So we think this is an up-$100 barrel price environment and $100 per ton carbon price, in order to introduce exactly this strategy to slash down the emissions. We approved projects. Some thresholds, less than $20 per barrel, CapEx plus OpEx, or less than $30 per barrel, the tax, tax break even. And in terms of emissions, new project, but emission intensity lower than the average of the portfolio. So every year, it's more demanding to our teams, to Namita teams, and Nicolas and Stéphane team, but it's very virtuous. Since we have implemented that rule, you can see the trajectory. Trajectory is really decreasing. I think this is what society expects from oil and gas company. LNG, which of course, is at the core of our strategy and our growth. Of course, we have established a global integrated LNG player, from upstream to liquefaction, trading, shipping, regas terminals, to long-term customers. We have a strong position, in particular in Europe, with more than 20 million ton regas capacity, which of course, in the present market since last year, have a own value in order to have access to the European market, and to, in fact, be able to safely market for LNG, in particular, US LNG. We are the largest US LNG exporter. We have, today, a supply of 10 million tons. We announced this summer that we have joined a new LNG project, Rio Grande LNG in South Texas, very well located, and where we have a, we keep a commitment of taking 5 million tons. So we have more than 15 million tons of LNG to supply into market, an increase of our growth, the business between 2023 and 2030, of more than 50%. Of course, we have to grow our LNG carrier fleet. Globally, it's in line with our expectation on the market. The second pillar, after oil and gas, oil, LNG, is integrated power. Stefan, of course, will come back on this, more detail than this slide. This slide is fundamental to me because we have, in fact, really, worked in order to set a strategic framework to deliver profitability out of this business. We, we, you know, since the beginning of this year, we published the integrated power results. You've seen that, we'll make this year, we are on the way to make EUR 2 billion of cash. We have a return on capital employed around 20%. So the markets are, of course, positive, which is what Stefan reminded, because a little... But, when we look to the way we want to develop this business, we will be back in 2025-2028, and we target a return on capital employed, 12%, which is more or less equivalent to, to, upstream return on capital employed of, at $60. So you know, the debate, and so we want this company, you could say, maybe you call it a cautious environment, but it's 12% return on capital employed on oil and gas at $60 and integrated power. So how we will do that? Fundamentally, because we think to develop this business, I would say, as an integrated energy business model, what we've done in oil and gas, not as a pretty multi model. We have no debt. We can leverage our portfolio balancing to capture value, in particular, from our current exposure. We have to work hard, like in oil and gas, to lower the costs. You know, it's a commodity, so on CapEx and on OpEx, strengthening renewables industry is difficult. We are leveraging our. The fundamental product we want to sell at the end is a Clean Firm Power to customers, because this is, I think, where we can have an added value. And again, Stéphane will come back on this, all the engines of the total profitability for Integrated Power. The important, of course, for us, is to understand that this strategy of being a no merchant exposure fits well, of course, in, I would say, deregulated electricity market, which Europe, the U.S., Brazil, Australia, which will be the core focus of our activity. Present, in fact, today, in our portfolio, more than 70% already of the portfolio, so we are completely focused. We have also, and it's important to notice, a strategy to combine to bring renewables and electricity in our oil and gas countries. Why? Because these countries themselves want to transition, but because also there is a leverage in both ways. You know, we contract, which we managed to sign in Iraq, in fact, the first discussions were around with the authorities about gas and power. And, because we were able to discuss about gas and power, and power in particular, but then to finance the full project, we put into acting, into, into the contract, an oil field, which will increase its production from 50,000 oil product to 200,000. And it is the same somewhere in some other countries like Libya. So there is a leverage in that way. There is also in the other way, the fact that because we are an oil and gas country, we are a main player, we can have access to, I would say, a very interesting, renewable contracts and projects, securing the revenue through our oil productions, like, in Angola or Mozambique. That's the primary focus of our activity. A word about the low carbon molecules, in this presentation, where we spend more or less $1 billion per year of CapEx. The full idea is fundamentally to use our European refining assets as a base to, first, transition them, and second, to also, on our side, develop our businesses on two pillars. One is sustainable aviation fuel, on the right, because we can convert our existing refining assets quite efficiently, and co-process some of the biomass feedstock in our refineries, in order to develop this attractive business of sustainable aviation fuel, with an ambition of 1.5 million tons per year by 2030. The market will be around 20-25 million tons by this global market, the horizon. Of course, what is key is to secure the feedstock. So we are, we made some deals already with some animal fats producers in France. We are also, in order to prepare the future, looking to new technologies, in particular, alcohol-to-jet, will offer us access to another source of feedstock for future development in sustainable aviation. All that being supported by the EU mandate is why Europe is finally at the end, for us, a good playing field, because the European mandates through the Green Deal are really supportive of creating this new demand from low carbon molecules and offering, in fact, profitable, let's say, playing fields. For hydrogen, the same, it's other low carbon molecules. But there again, we will use our refineries. On the one side, we need to decarbonize our European refining system, and we have the equivalent of around more or less of 5 billion tons of CO2, which are today, which is Scope 1 or Scope 2, or Scope 1 plus 2, linked to hydrogen use in our refineries. So the idea is to decarbonize that by using green hydrogen. Why do I say green or biohydrogen? Because in Europe, according to the European regulations, the new one, which have just been created by the government, there is what we call the RFNBO regulation, which means renewable fuel of non-biological origin, which offers, in fact, an economic scope. But all this, when we will use green hydrogen or biohydrogen in our refineries, we'll have an economic advantage, so these new products will be again the EPA, showing the economic space to develop some projects. So we will develop some local projects, like we are doing today in La Mède, on 120 MW projects, which could be phased in three first phase, but we are looking both options. In Grandpuits, where we have a biorefinery, and we can produce biohydrogen together with Air Liquide. We have also already signed some supply agreements in Lorraine and Normandy, and we have just announced and issued a tender for, in a way, as well, to establish, to contribute, to establish this green hydrogen industry, a large tender to supply by up to 500,000 tons per year. We'll see what will be because we will receive. So in terms of CapEx framing to support this strategy, we keep the guidance we gave you, fourteen to eighteen billion dollars for cycles. For the next five year, this fourteen, eighteen, we think, because we are, as described to you, we are bullish on the price decks. We are on the base of sixteen, eighteen, but it's important to remain with the global guidance. We have identified, in the plan, $2 billion per year for downward flexibility, particular or short-term CapEx, which we could arbitrate, on both sides, either on oil and gas or integrated power. And the scheme you see there, it remains the same, but I think it's very important in an energy industry to be, to have a, a CapEx framework. We go through cycles. So again, $4 billion in integrated power, an additional $1 billion on low carbon molecules, which makes $5 billion, more or less a third less than the CapEx. And on oil and gas, to support, support, of course, our existing production base, as well, also CapEx, and the rest being dedicated to the new projects. Just a slide to illustrate what I just described with the 2023 activity. On oil, we have acquired a concession in Abu Dhabi, Sarb and Umm Lulu, very low cost, low emission, by the way. Abu Dhabi being at the forefront of electrification of the whole oil operation, so it's sitting very well with our objectives. Vietnam, we are going now, we are working now towards FID by end of 2024. In the same idea, we have divested two businesses in 2023. One is the oil sands, because they don't fit with the refocusing of our business on low cost and low emissions, and as well, our EU retail business, in order to refocus, and Stéphane will comment on most of our activity in Europe, on EV mobility. The gas, we had this sanction of Rio Grande LNG, which is registration of the strategy, plus the first gas. In integrated power, two, two major operations. One is a full integration of Total Eren, which was about 5 years ago. We, we owned 30 percent, now we are 100 percent. We had a very good multiple to acquire it, so we exercised the option. Now we are integrating as well as human resources, we employ the full strategy of integrated power. We have been successful in offshore wind, and Stéphane will explain you why this was pretty consistent to the strategy. Last but not least, Iraq is a sort of flagship of our multi-energy strategy, which combines oil, gas, cutting down gas flaring, producing gas and power. And it's success. We came back in Iraq, where we are born 100 years ago. In 2024, will be the end of the year, 100-year anniversary of the company. In 2023, in terms of cash flow allocation, you see that we'll generate, here, at the end of the year, about around $37-$38 billion cash flow. So we invest 16-17 net capital investments, to build up to present eight, and I will come back on it to the $9 billion. Cash will be allocated to, comes to strengthen the balance sheet. So the last slide of the strategy, which is a good summary, more energy, growing the energy production, less emissions, and growing the cash flow. So, all in all, between oil and gas, and our integrated power, we'll grow our energy product by 4%. It's the core of the future growth of cash flows. We continue to lower our emissions. I already commented top one and two, I will not do it again. Just that we follow, because for me, it's a long debate about top three, but I'm not convinced by top three absolute target, because I think it makes a little sense. One, which for me is important, because it's it demonstrate, in fact, it's a marker of a transition strategy. It's the intensity of the life cycle carbon, so Scope 1, plus 2, plus 3 type of products. And last year, we announced that we want to reduce by 25% between 2015 and 2030, so that means the company is transitioning. I think we'll be already at -12%, so we are well on the way of making this transition. All that, of course, the objective is to continue to grow cash flows, and in order to be able to grow distribution, will be my conclusion later. What I described to you, between 2021 and 2028, 2021, that was the real price deck, $71 Brent, $16 per million BTU for European gas, and the refining margin was quite low. If we take a sort of $80 per barrel development, $8 for the gas, and $35 per ton for refining margin, considering the volume growth that I just described, will generate more than $10 billion of additional return. And it will be explained to you now by Nicolas and Stéphane for detail before I come back. Thank you, Patrick. Good morning, all of you. It's a pleasure to be there. So over the next six slides, I'm going to focus on the oil and gas pillar, and particularly our projects, and focus on the performance and the personal excellence, and what we're doing to achieve it. So as Patrick indicated, we expect to increase our oil and gas production by 2%-3% per year over the next five years. As you can see in the chart, a good chunk of this growth is coming from gas and particularly our LNG projects, and I will give you a bit more details on this. With also some growth in oil production, thanks to a very rich portfolio of projects, which I will show to you as well in the next slide. While growing our production, of course, our focus remains on the, the value on the cash from these projects. You can see that this increase in production will lead $3 billion increase in this issue. Oil and gas pillar, the same nominal project between the two years. Oil. Of course, we are very much focused on the execution of our project to deliver on the production growth that I have done just before. Actually, a lot of our teams are working on that currently. We have a rich pipeline of projects, which you see on the four main projects. Integrated project in Iraq. All the agreements were signed in July. Our entry in Ratawi was effective in August. Today, the field is producing 60,000 barrels per day. We are launching the phase 1 upgrade to this project production. This for the company. Brazil, we are continuing with Petrobras, the development of Libra field, a great success story. The Mero-1 FPSO was started last year. Mero-2 is expected to start at the end of this year, in December. On Mero-3 and Mero-4 will follow, very productive field, allowing a lot of people test on, on low emission intensity. In the U.S. as well, two deep offshore projects, Anchor and Ballymore, starting next year and the following year. And last, Uganda, where we are now, you know, in the development phase of our Lake Albert project. Drilling is ongoing, facilities construction has started. It's a large project with a material stake for us, 57% interest, with the production of 130,000. So all together, all these projects, if you add them, they represent more than 300,000 barrels per day of new production by 2028. Also, for above $3 billion annually to $50 per barrel. A pretty good upside, price upside, with FFO increasing to $2.5 billion annually, at $7 per barrel. All these projects, they meet our requirements, of course, in terms of cost, and also emissions. Of course, I'd like to give you the technical cost, the full technical cost of this project. So you can see, of course, the onshore projects with a very advantageous technical cost, Iraq, of course, and Uganda. Deepwater Brazil, below 20. Ballymore and Suriname, also, around $20 per barrel. LNG. So LNG, as shown in the production chart before, we expect to deliver a best-in-class growth of our LNG production, with four flagship projects. First one being, Qatar. Our combined position in the North Field, East and North Field South Extension projects are now ongoing. This will bring us 3.5 billion per annum of equity, and also of offtake. With low unit cost, due to, you know, the energy in Qatar, and the side effect. Rio Grande LNG, Patrick mentioned it in the U.S., where we entered in July with a material offtake volume. Competitive project, very good site, no dredging, no piling, proximity to Eagle Ford and to gas resource. So again, a project that is competitive in the right term. On Papua LNG, we are progressing towards the FID, completing the engineering design of the project, with an FID targeted early next year. Again, the competitive project for energy that we managed to achieve with PNG LNG, so the first LNG project in Papua New Guinea. This project will add 2 million tons per annum of equity to our LNG project. And last, Mozambique LNG, where we are working to create the conditions for a restart of the activities. Target start-up in 2028. 3 million tons per annum in company share. Still a competitive unit cost for the LNG plant, because EPC contract was awarded back in 2019 in favorable conditions. So even with a certain set of activities, at an attractive $ per ton. When you see those projects here on the map here, good projects, most of them are well positioned compared to the... Let me come back on Suriname, that Patrick commented on. Suriname is a good example of how we can create value from exploration. We entered in Block 58 in Suriname in 2019. We've completed a number of wells, and now we've fully appraised the two oil discoveries, bringing together close to 200 million barrels of recoverable resources sufficient to have a robust development. The concept is now selected, so we're going to go for 200,000 barrels per day FPSO, full gas reinjection, FID targeted at the end of 2024, with the first oil in 2028. Again, this project meets our requirements in terms of unit cost on the emissions intensity. We'll access quite a lot of oil, actually, during the first reimbursement of the carry of Apache, our partner. And you see here, the internal rate of return, about 15% at $6 per barrel. Technical cost at $20 per barrel equivalent. A short payback project, but for year payback scenario. Alors, besides project, we continue focusing on maximizing the value of our portfolio. First, by working continuously on operational efficiency, on maximizing the production from our existing assets, and doing so, of course, safely. And by the way, safety and operational efficiencies go together. We continue to work on lowering our unit OpEx with the objective of keeping our OpEx $5 per BOE. So it's a competitive advantage of the company, the low unit OpEx, and we want to maintain that by working on, you know, lean operations on site, by working on the logistics, working on stock selections, and all the levers we have to bring our OpEx down. Of course, we are very much focused on the execution of our projects, on delivering the major projects I've shown you before, on time, within budget. Portfolio upgrading is important. Patrick mentioned it. I think what we've done in 2023 is a good illustration of what we want to achieve in a portfolio with the divestment of our assets in Canada. You see the technical cost of these assets in the chart in the middle. So obviously, the Canada divestment has a positive impact on our average technical cost. And with the entry in low-cost assets, Sarb Umm Lulu in the UAE, Iraq, plus the FID focusing on projects, you know, like Suriname, Angola, with a good productivity and with a fairly low technical. So overall, if you look at the chart in the middle, what it shows is that between 2020 and 2024, we expect to improve quite materially our average technical cost by about $1 per BOE. All, all together, producing oil and gas differently, what we want to do. And first, we focus on our existing assets. We have a target to reach zero methane emissions, effective by 2025 and 2030, -50%, -80%. And to do this, but of course, we need to measure our emissions, so I think we're quite proud that we developed a unique technology to measure emissions on our sites, that we have deployed on all our operated assets, all our main operated assets, in 2022. To be able to monitor our progress and make sure that we are on the right path towards zero methane emission. We are committed to zero routine flaring. Here, we will complete routine flaring on countries, Denmark and Nigeria. So basically, routine flaring will be divided by two, and we have a lot of other countries to address. We are continuing to work to deliver our energy efficiency improvement plan, $1 billion, which is about reducing greenhouse gas emissions, improving energy efficiency, but also reducing our energy cost on our OpEx, and it's also about good business. For new projects, we are going to play on all our new projects, so zero flaring on all our new projects. It will be the case in Suriname, of course. Each time we can, we are using renewable power also to meet our upstream projects' own power requirements, and we are doing this in Uganda, in LNG as well. Papua LNG, interesting project, because we are going to reinject all the native CO2 to one reservoir from day one. And also new trains will be electric trains. So this will allow Papua LNG to have a best-in-class greenhouse gas emission intensity. And for our offshore projects, we are working on improving the efficiency of the power generation on board our FPSOs. And one way to do this is to implement combined cycle gas turbines offshore. And last, we innovate in e-fuels. Good example of this is our investment in the joint venture with TES in the U.S. to develop a project to produce e-natural gas, e-methane with a renewable power to produce hydrogen, and then a combination of this hydrogen with biogenic CO2 with the objective of producing 100,000-200,000 tons per annum of e-methane. One advantage of this is that this gas is fully compatible with existing infrastructure, so can be monetized to the market easy. I will now hand over to Stefan for integrated power pillar. Thank you, Nicolas. Good morning, everyone. I hope you enjoy the view on the sunny day. For me now, I see plenty of gigawatt on dollar coming from our solar plant in PNG. So I guess that's what we mean by the transition. So I'm going to present you the second pillar of our growth strategy, integrated power, and in particular, how we plan to build a profitable cash engine. And I guess that profitable, it's obviously a relative notion, but for us, as Patrick mentioned it, it's quite precise. That means reaching, reaching 12% return on capital in the coming years. So to do that, obviously, we can't just copy or become a pure renewable player, which sell intermittent player power and and bet on decreasing cost and decreasing interest rate. We can't copy neither the business model of utilities, which is based on on guaranteed price and high leverage, because we know that those business model are not going to deliver the kind of target we are looking for.... That's why our strategy is really to deploy what we call an integrated power model, where we will leverage on our strengths, the size, the balance sheet, to extract value from on one side, taking more merchant exposure, and on the other side, selling clean firm power. For that, the integration is key, and that integration is going along two two dimension. The first one is the one you see on the left side, is the integration of different type of technology of production, where we plan to blend intermittent assets coming from renewable, and flexible assets coming from gas-fired power plants, storage, pump hydro, hydro, so that we have a good blend that allow us two things. One, to manage our merchant exposure. Two, to sell to the customer and extract value from that clean firm power. Obviously, the blend depends on, on which market you are. The weight of the various type of, technology will depend on the market we are, but the basic fundamental idea of that integration is integrate flexible and renewable at the same time. The second idea of the integration is to integrate along the value chain, to be able to extract more value, from the way we sell our electron. And to do that, there are two ideas. One is clearly to build a very strong trading, exactly the same way we have done on oil and gas. Today, we have already a big team, big power team in Geneva for Europe. We are building it as well for all the market in the U.S. from Houston. And the last idea is to develop our marketing capacity, targeting the large B2B, where we are going to sell, at the same time, structured corporate PPA, renewable corporate PPA, but as well, what we call the Clean Firm Power, which are fundamentally structured PPA. We'll come back to that. You know that we have as well a B2C presence, especially in France, Spain, and Belgium. But I would say that the key of our focus is really on B2B, and on B2C, we'll try to consolidate our position. With all that, the target is to reach above 100 terawatt of production by 2030. And you see that I'm talking about terawatt, because at, at the end of the day, what matters is production, because production is revenue, not that much capacity. And I'm talking about 100 terawatt of forward production, coming obviously for renewable, but as well from the rest, because part of the value is coming from that integration. Why do we target 100 terawatt? Because at the end of the day, size matter. Size matter, and I will come to that, in terms of building a meaningful business for the company. And you see that with all that, we will be roughly 20% of the energy we sell by 2030. And because if you want to count in that game, especially, with the supplier and the contractor, you have to be big. So to implement that business model and to make it profitable, we have, we are going to action fundamentally 5 levers on which we have worked in the last 6 months and where we have now full action plan, people in charge, and we will, we'll do as we do in oil and gas, very methodologically implement all that. The first idea is that that model of integration only works on the regulated market. So we are going to focus our growth on the regulated market. Patrick mentioned it, one-third in Europe, one-third in the US, a bit of Brazil and Australia, and the rest will represent less than 20% of our sales. That's one. Second, we need to grow 4-5 times versus our current renewable production of 20 TWh, and double our production of flexible asset. To do that on renewable, today, we have 20 GW of capacity, six under construction. We will meet our target of 35 GW by 2025. And, as you know, we have a pipe of 40 GW of early or mature, or mid-stage project, post-2025 to fuel the growth. Then the question is, how to make that profitable, and here, there are four dimension. The first one is that, we will be putting in, on stream around, ten gigawatt of capacity after two thousand and twenty-six. And to develop that, obviously, you need to industrialize that process. So that means focus on a limited number of countries, but where we, we can have big project and good project. And the way we have done that was to really partner with the top player in the c- in the market where we are. Electricity, and especially development, is a, is a local business. And we, for example, have developed in the U.S. by partnering with, with Clearway, which is one of the top five developer. In Brazil, with number one, with Casa dos Ventos. For example, in, in India, with Adani, and really try to leverage that strength to be able to build a very strong portfolio.... Obviously, on the development side, we buy as well project like other from developer, but we want as well to have our own platform of development, which is the case, for example, in France, in the U.S., in U.K., or for example, Portugal or Greece. That's for the development part. Then obviously, if you go in the merchant market, you are exposed to cost, and you need to compete on cost. And we aim to have the lower cost of the industry and of the merit curve, exactly the same way we did it in oil and gas. And so we target to be able to lower our unit OpEx and CapEx by 10%, and to improve our efficiency to target really the first quartile of the industry. Obviously, to do that, you have to benchmark your asset internally, externally. You have to standardize your design to be able to use your size, your size effect. And so today, for example, we have standardized the design of our solar plant to limit to five or six models. You have to play on your purchasing power. We just signed two capacity reservation contract, one with First Solar and one with Jinko in China, where we see that in average, versus the rest of the market, we can lower our cost of supply by 5%. And last but not least, you need as well to control your operations. That means, for sure, have in-house operation on the way you operate your, your solar and, and wind farm, but as well, centralize all that, so that, you can, operate them in real time and, and in the most efficient way. Part of the difficulty of renewable is that you have thousands, if not million, of type to manage, and you need to realize when something goes wrong very quickly. And for that, you need a lot of digital and, and AI, which now we have. So that's for the develop better, produce better. Clearly, the question is how to sell better, and on that, there are two dimension of, as I said, one is to take more merchant exposure. We have a view today that a small developer needs to hedge his production, and for that, he's ready to pay a premium to get a long-term as-produced PPA. And there is value to be taken to take merchant exposure in that market, same when you have flexible asset. And second, on the 70% of the production we are going to sell, here, we are convinced as well that we can extract value by selling to the customer more sophisticated product. Or the first one is just to sell clean firm power, because at the end of the day, you want to buy power when you need it, not when it's produced. And here, we clearly see that there is a premium to catch. Obviously, to do that, you need a strong short-term trading, real-time trading, that we have built in Europe today and that we plan to deploy in the U.S. as well. Last but not least, the portfolio. As I said, you need the good blend of flexible asset on one side and intermittent on the other side. And that's why we need to add, if I take, for example, Spain, where we have a large solar portfolio, we need a bit of wind. Exactly the opposite in ERCOT, where it would be... Sorry, is the same in ERCOT, where we need a bit of wind. There are markets where you need to add storage. So that's a dimension on which we work as well. And then there is a cost of financing all that. We see two dimensions: using our balance sheet to minimize the cost of the debt, that's one. And second, you know that in our business model, we farm down 50% of the asset at COD, and here, that's a lot of sales where we want to industrialize that process and work with specific partners. So that's our strategy, and the bulk of our strategy. There are three subjects I would like to mention in addition to that. The first one is offshore wind. Why offshore wind? Offshore wind should represent 10%-15% of both our production and investment, so that's not the bulk of our strategy. But nevertheless, you... It's an interesting technology, but as well, a technology, and we've seen that some of our peers that could struggle. To remark on that, it's true that costs have increased and interest rate increase, that doesn't help. But at the same time, it's clearly a technology that is quite close of our traditional oil and gas activity. Long project, CapEx intensive, of course, offshore, where you have to manage the execution risk, things at which we are quite good. So we believe that clearly, offshore wind has a role to play, but we want to do that selectively and profitably, and choose carefully our market... and the market on which we want to go are, one, market where there is good wind, because you need competitive asset. Those assets need to be competitive, and one of the interesting aspects is especially when the grid is paying for the connection. It's not the case everywhere, but which makes a big difference on your cost of production. And of course, bottom-fixed, because today, bottom-fixed can be in several markets at competitive and grid parity, and that's not the case for floating offshore. Finally, if you want to be completely consistent with your model, you need to have the freedom of doing whatever you want with your electrons. And that's why we notably chose the German power market, because Germany has all those characteristics. One, it's a very dynamic market in terms of corporate PPA. Second, you can blend offshore with, with solar, and we have project in Germany to do that. That's a market where, exiting from nuclear mean that, costs are done by, the price of gas and CO2, and today, we see that PPA are above, $80 per megawatt hour. So structurally, it's a very interesting and promising market. And at the same time, when you look at offshore wind, you have low technical cost because it's bottom fixed, load factor are very good. and we have the possibility to access to a long-term lease in what we consider as attractive entry conditions, because at the end of the day, you pay only 10% of the bid amount we have paid, and as I said, the grid connection is paid by the state. Then it's true that you will have to pay a kind of royalty or profit oil, if you wish, to go to compare with the model in E&P over time, but it will come when you have decided to take your FID and over the life of the asset. For all the assets, that's why we went for that option, and we are very satisfied to have wind free gigawatt, and we are confident, ideally, that we will deliver on that project, like the other, the return of capital as mentioned of twelve percent. Second remark, as Patrick mentioned, we stay on regulated market for two reason. One, because you are the oil and gas country, and as Patrick mentioned, on that, we can leverage the multi-energy model. We can get good contract, like in Angola, Qatar or Kazakhstan, or contract with big size that help us to leverage our position with our supplier. And at the same time, that's a way as well to get good oil and gas contract, like in Iraq or in Libya. So here, the idea is to be profitable. We don't go in this country not to be profitable, but we believe that we have a competitive advantage. That should represent around 10% of our production, where the extra value is not going to come from integration with flexible asset, but from our oil and gas presence. And then you have the rest of the portfolio with two remark. You still have markets that are interesting, where you can create value. That's what we believe we are doing in India with JV, with Adani Green company, where here, the idea is to access the asset, and we have two JV, 3 GW, called AGEL23, and the new one we have just signed of 1.4 GW. And then we inherit from the Total Eren portfolio a large number of countries where at a very good price, as mentioned by Patrick, because multiples of EBITDA were low, where we are reviewing that, and we will monetize for sure non-core assets. That's one of the tasks for the months to come. Last but not least, electromobility, where here the target is really highways and city hubs for EV charging and B2B segment. Why is that? Because there is an obvious synergy with our current position, leveraging our presence on highways and city hubs. And as you can see, we are already the number one in France, with more than 1,000 Hyper Chargers already installed, and where obviously, we try to secure the scarce prime locations. As well for B2B, we have relation with customer on the B2B market, thanks to our fleet card system. And here, we want to use that specific relation to provide mobility services to our customer and to deploy our EV charging. It's clear that on B2B, even if it's necessary, not large volume, there is a synergy as well with the integrated power business because that's a demand on which you can make load shift, which has clearly some value in terms of demand response. Finally, but like, there, it's much more selective, where we continue to work on the B2G, but we are selective because we don't want to sacrifice profitability on that segment. All that should lead to a stronger increase of our production, going from 30 TWh to above 100 in the next 5-7 years. And obviously, with growth on one side and improvement of OpEx, CapEx, and revenue, we plan to be able to go from $2 billion cash flow generation in 2023 to more than $4 billion in 2028. And why 4 is important is because we plan to spend $4 billion per year to do that, so the target is clearly to be net cash flow positive by 2028. I'm done, and I will hand over the floor to Patrick for the part you are waiting for, the distribution. You are expecting that. But in order to grow the distribution, we need to grow the business and cash flows, you know, there is no miracle. And so why should you continue and even or more acquire investment in TotalEnergies, which is more important? First, some figures have been charted, but which summarize, in fact, I would say the various presentation. So the cash flow growth, with the same price deck, I don't say that the 2028 price deck will be the same by 2023. I I just say the same price deck, whatever it is, will generate $6 billion cash flow additional from a pure volume effect around more than $3 billion in Upstream Oil and Gas, which was explained to you by Nicolas. The Integrated Power, an additional $2 billion. What was not described, but I give you the figure, in the downstream Petrochemicals, plus low carbon molecules, which I mentioned with through sustainable aviation fuels and these RFNBO molecules in, in Europe, around $1 billion. So it's globally a volume effect of $6 billion. You have the price sensitivities, which do not move too much, $3 billion for $10 per Brent, $400 million for $2 per million BTU of European gas price, and $500 million for $10 per million refining proxy. By the way, on the proxy today, it's a good sensitivity because the margin is quite good and quite high. More importantly, on the right side, you've seen there the important metrics on which the board of directors, in fact, works. The first one is at $50. If I take the 6 years from 2023 to 2028, we will generate, you can see more than 100, between $150 billion and $170 billion. We spent in CapEx discipline, capital investment around 6 years, around $100 billion. The existing dividends represent more or less $50 billion. So we have a... in fact, a post-dividend break-even, which is lower than $50 per barrel, which is, of course, very important metrics, in particular, when you combine it with the fact that, thanks to the cash flow from the year 2022 and 2023, the balance sheet, the gearing is at lower 10%. So, that, of course, will allow some flexibility, I would say, upward flexibility on the distribution policy. And at $80 per barrel, with the metrics we mentioned, in fact, we are generating beyond the capital investment, more than $100 billion of cash flows, part at the dividend, $45 billion. But you see, you have room to improve distribution for dividend or buyback. And this is what this was the key with this slide and discussion we had at the board, which led to this improving shareholders distribution guidance that we give you today, with the strong confidence of the board. We had, again, a meeting, a board meeting this morning, by the way, after a strategic seminar last week, in order to consolidate all the positions at the unanimity of the board. We thought last year we went out of traditional, I would say, 30% guidance to 35%-40%. With all what we described to you, and in fact, a strong confidence in the capacity to grow the business, either Oil and Gas or in Integrated Power, and both pillars are important, to be able to, to give a guidance above 40% of, the cash flow from operation distribution, distributed, being distributed to shareholders, either for dividend or buyback. For 2023, in April, we mentioned that, when we announced that we were renouncing to the IPO of the Canadian Oil Sands, that we are divesting with a deal with, Suncor at that time, that the board will look to what is the best way to return, parts of these, proceeds to shareholders, either through a buyback or special dividend. We had some discussion with major shareholders. We concluded, but today in the market, clearly, and because as well, we consider that even as the share price went up in the last month, there is still room to go higher. And so I know I see Michele smiling. He has always been a strong believer in buyback, but the board has convinced, so we decided to allocate $1.5 billion of this proceeds to buyback. So we raise the buyback from $2 billion to $9 billion. We maintain the $2 billion during several quarters. We make an additional $1 billion, which should lead to a distribution more or less around 44%. So we are well, you know, last year it was 37%-40%. So I think it's a clear change in the way we, which as a company and its board are looking to a primary first importance of distribution. But again, it's linked to, the fortress balance sheet and our capacity to grow, the business. So I think it's important, guidance and indication. I would say, I'm sure I will have the question, what do you do for next year? I would say for next year, we not have a special proceeds from Canada, but I would say, going, maintaining this $2 billion per quarter is a nice pace in this type of environment. And then if you combine with the 40%, you can see that we'll be above 40%. Knowing that, as I explained you last year, in terms of dividend, we will buy back with $9 billion. We will buy back more than 6%, 6, 6.5% of our, of our capital, of our equity. And so that will immediately feed the growth of the dividend next year, you know? So, so you have some, this year we grow by 7%, 7.2. I think we should not be surprised next year not to be around these things, this type of growth. So I think this, consistency, what we target as a board is to be more consistent in the distribution policy, in fact, years after years, because I know from time to time you had some question mark, but our investors needs to be, I want to reassure them that a strong commitment to this distribution policy. And I don't forget when we speak about investment case of TotalEnergies, the fact that, for some investors, both sides of the Atlantic, by the way, our ESG policy is also taken into consideration. We have a strategy, in fact, it's not for, a transition strategy, which has been well explained, on which we stick and which will deliver, again, the fact that we transition our own business, but growing the energy production, and 25% less carbon in our scope, in, in our carbon intensity index is very important. So you can see that some, then this slide, you have some key agencies, I think, in evaluating the different oil and gas companies. We know that oil and gas companies are not considered as a star of ESG, but among the, among this group, I can say that we are today recognized as having a good position, and we have improved it in MSCI, Sustainalytics, Moody's or S&P Global, or maintain it. So among our peers, we are continuing to lead the pack, and I think it's important for the investment case of the company, and I hope investors will appreciate it. Last slide, which summarize, I would say, as a global presentation. Again, it's more energy, 4% of 2%-3% oil and gas, more on integrated power, but 4% growth average. Less emissions, -40% intensity, scope one and two, -25%, scope one and two and three in intensity. Growing cash flows, which is even more important because this is of course what we intend to do in order to grow the distribution. We keep, I would say, the capital allocation framework that we described to you in the previous years, continuing to have a sustainable growing dividend, fed in particular by the buybacks. A disciplined CapEx policy, but through cycles, but which allow us to grow our businesses, so we are comfortable with the guidance. The balance sheet, the fortress balance sheet, Jean-Pierre has a special objective to, to raise of creating to AA. I think on Moody's side, he's optimistic. We'll see if it comes. And the surplus being shared through buybacks fundamentally. We used special dividend last year, but it was an exceptional year. Primarily, I would say, tool is a buyback, because again, at the end, the rerating of the share value is our primary objective with this new guidance of more than 40% payout through the cycle. So thank you for the attention, and we'll be now happy with my colleagues and not only Stéphane, Jean-Pierre, Helle and Nicolas, who are there, but also in the room, we have Thierry and Bernard and Namita, with whom some of you will have some discussion this afternoon. I will be able to, to come back and answer to your questions. Thank you for your attention. Let's start the Q&A session. So the basic rule today is we will alternate between a question in the room, priorities in the room. We'll have also audio questions, so please introduce yourself when you are asking questions. I see a gentleman here who raised the hand. Go ahead, please. Please introduce yourself. Hi, everybody. Sam Margolin with Wolfe Research. Thanks for the event, and thanks for taking questions. I just wanted to clarify the growth targets, and I know it's all on the slide, but I just want to make sure even I can understand. Three—because $3 billion does seem somewhat conservative with an oil and gas, so I just wanted to see if there were also some other asset sales embedded in that or base decline, or if it's simply a price deck issue. And then specifically within that, with Suriname, if that's excluding the payback and the carry, too, because that affects the 2028 timeframe. So simple, in the shorter version, $3 billion—No, there is no price effect. There is, of course, you have the. Don't forget that we have a natural decline as well, you know, for portfolio. So you have a 3% natural decline. So when you increase your... For these four projects, I think Nicolas gave you some precise figures. You are adding 300,000 barrels per day and some cash flows, but we are losing part of the cash flow as well. So it's a balance between both... In divestments, we don't have major divestments in the view. We continue to monitor, might have some mature assets somewhere time to time. We said no, it's part of the dynamic that I want to maintain in the company, because I think it's worth continuing reviewing. But the $4 billion are consistent with, I would say, the rate of 2, 2 plus, 2% plus of growth of the hydrocarbon business according to our, to our metrics. The Suriname carry, no, Suriname carry, does not have any real impact on that. It's, I mean, on the cash flow, I don't know why there is 28 we will produce, so normally we even have some cash flow coming in. It has been neutralized, I think, in the, in the paper. Got it. Okay, and then- Because, again, the carry, we got access to the oil. We have 75% of the cost oil of our partner, which is for us. So in fact, it's this carry, honestly, it's not a big deal for us. It's just a sort of rule that we repay quite quickly in three years at $60 per barrel. Well, so that was my follow-up about, about the Suriname carry and with respect to capital allocation and distributions, in particular, 'cause there's layers of it. There's the concession, cost recovery, and then you have one from the partner, too. So the cash flow almost manifests like a, like an asset sale 'cause it's so- Yeah ... front-loaded and so- But for me, yeah, but again, there is a, the Suriname... I'm not sure to understand fully your question, why you are, what is the background of your question on this impact? Because the PSC will work normally. We have our share of our CapEx. We are paying part of the CapEx of our partner, and we recover all that in three years from- Cost oil ... Their Cost Oil. Their Cost Oil, not our Cost Oil, their Cost Oil. We capture the oil, so it represent quite a big amount of oil, in fact, which asks for us. The higher the price will be, the quicker it will be. Okay. Yeah, the question was just if that impacts distributions when it comes in at a different pace- Positively. Than... Positively. Positively. Okay, thank you. Positively, not negatively. Positively. Okay. Thank you. Okay- As you know, as you said, we are always considered as conservative. We consider that if we say today more than 40% of distribution, it's because we believe we will do, deliver it. Another question in the room. Chris Copeland, on the... Chris, on the other. Chris, or? Yeah. Thanks. Hi, it's Chris Copeland from Bank of America. I want to go back to the last comment you made, Patrick, the fortress balance sheet, and attach two quick questions that probably you're used to hearing from me. The first one, you've laid out a number of organic growth options, and I wonder what your thoughts are regarding your appetite for inorganic growth? Because that fortress is going to get a lot stronger, I think, in the next few months. You're getting $8 billion of disposal proceeds through the doors. So, maybe you can explain to us a bit more how strong the fortress will need to be, or maybe Jean-Pierre, on double A or not, any characteristics around how much stronger the fortress needs to be. Because it looks to me like you're close to- Yeah, but the $8 billion, we already this year- Yeah. Maybe you didn't notice, but we have been quite active in the acquisition side because we acquired for more than $6 billion. So the M&A activity is quite active in the company. So, but when we acquire, we need also to divest. So the $8 billion are already somewhere quite spent, so don't expect much. But appetite for inorganic, you know, we will stay always the same comments. You make a good acquisition when you are countercyclical, and so you might have some opportunities, like the one we had last year in Abu Dhabi, because one company was willing to divest oil and gas upstream. We have another strategy, so we acquire. That's the point. But honestly, oil and gas assets today are quite on the high side. On the other side, obviously, you can all see that interest rates going up in the renewable space, there are a lot of decrease, but it's... Be patient, it will continue to decrease. Back to reality, all back. Now again, we have quite a large portfolio, so we are satisfied again. You can expect us to do on the integrated power, to do what this Stefan described to you, which is more to complement the portfolio through some flexible assets. You know? Because we need that. To execute a strategy, we need to have a mix. And we have some in Europe, we don't have that in all the markets we are targeting, so this is more the core. Not large organic, inorganic growth is in our view today. It's not a priority. The AA, again, I think, I said, the metrics which are used by Moody's should allow us to get it. Yes, made the math, and so it fully led to an upgrade. Standard & Poor's, to be honest, is more complex because if you want to be AA in Standard & Poor's, I should stop the buyback and allocate everything to the balance sheet, which I'm not sure you investor will please. So we have, so this was... No, no, we express, we expressed all that to the board, and we came to the conclusion that it's a, it's a... Now again, as I said last year, the fact that we have a gearing under 10% has changed a lot flexibility in all this, compared to previous years. So we are satisfied to that, and it's a right balance. But you wouldn't be comfortable paying out more than free cash flow? It depends on the year. Again, I will commit to 40%. Thank you. Okay, question from Michele, maybe. Yeah, sorry. ... Michele Della Vigna from Goldman Sachs, and congratulations on the leading payout ratio announced today. I had two questions. The first one goes back to Helle's slide on LNG. It shows some mild oversupply from 2028, and I was wondering if that is somewhat influencing your contracting strategy with probably more long-term oil-linked contracts. And I was wondering how the environment for that is evolving, and broadly, what kind of percentage of oil price we can expect for contracts signed throughout this time period? My second question is on costs. We are seeing an enormous shift in the industry towards short cycle investments, which are very drilling intensive with a lot of well completion, and I was wondering if you're starting to see inflation emerging there, which at some point could make the economics of those developments actually less attractive, even in a generous oil price environment. Thank you. So good, two good questions, like always with Michele. No, I mean, on the first one, yes, we have to be transparent, but again, if you look to the slide, you've seen that the oversupply might come from some pre-FID, so maybe some people, maybe it's a slight warn of us, you know, not us. Be careful. If you FID your project, you can come. It's true. Having said that, that's. It's cyclical. Yes, we'll have some few good years in front of us, but after that, we might face that. Knowing that in the LNG industry, delays to deliver plants are quite, are not unusual, I would say. You know, these huge projects. So yes, the conclusion is right. It's a good time today because it's more a seller market than a buyer one to secure some long-term contracts with oil index, exactly that. But to higher level than what we experienced in the last previous five years, so this is what we do today. For example, on Papua LNG, we are not far to conclude oil, oil link project contract. I'm not sure I can deliver to you, maybe in a one-to-one discussion, but publicly, what is the percentage? Because I think my... but I'm going to Qatar to inaugurate NFE and NFS, and I'm sure that Sal will not be happy if I begin to disclose this type of percentage. Nobody is clearly higher today, and so it's a good opportunity, and that's a primary focus today for Stefan teams, LNG teams to market it. So if that's the right answer to bring. Again, that's a market, but it does not mean... but that means as well that we have a good portfolio today, and we don't want to add more at that horizon, you know? So until 2030, we have all these projects. It's okay. We have big growth. Let's concentrate on delivering them. That's the first point. But again, if that happens, that means that the price of energy will go down, and then the demand will remain. Because the 5% that was mentioned by Helle for us is an average. You don't see that today, but you could say, remember, 2015, 2020, it was more 10% per year because it was supported by a lower price, and we know that there is an appetite in Asia for LNG, but it's linked to the, to the price as well. So it could, might help to the demand. It will help the demand to rebound. Costs. Costs, yeah, we have a, a long discussion. We are working out on the rig strategy today, in order to secure lower rig costs, even longer term, maybe, making GV's, in order, so we try to be innovative in a way to, to control the costs. But that's true that you have today, I see, I observe in the drilling rig, companies, the strategy, they prefer to keep some rigs stacked in order to control. They have OPEC, like OPEC control, you know, rather than putting more rigs in the market to see the, the rate going down, so we are facing that. Until now, to be honest, until 2023, because of our strategy in the years before, we are protected. Now, for the future development, it's something that we need to address. We see deep offshore rigs today around $400,000 per day, which is back to some old times, so we need to find ways to manage that. It could influence, you are right, some of these short-term strategy, but honestly, we'll, I would say at all, at this time, I mean, we with the metrics, we have less than $20 OpEx plus back CapEx, and as long as we stick, that's why we are strong on these metrics, we can cope with the costs. Okay. Question, maybe in ten- Maybe we should take one from abroad. I see Christian maybe first. Okay, so- We could alternate. You say alternate, so if you give the floor for everybody. Yeah. So let's alternate, and then we'll come back to all the- Okay. Don't worry, we will answer to all the questions. Christian Malek, you are, you can ask your question online. Team, can you hear me? Just checking. Yeah, very well. Great. So Christian Malek from JPMorgan, and congratulations on the presentation, and apologies I can't be there in person. A couple of questions. First, on the macro outlook, and specifically the long-term $80 view. Last time, last year, you framed the $50 barrel with upside flex to the long-term price. But so in our super cycle report last week, we got quite a lot of pushback on $80 oil price long term, which is well above the back end of the curve. So I'm wondering, what gives you the confidence in this outlook, especially as you've got IEA calling for peak demand this decade? And that's my first question, please. The second question, and related to that, sort of is, it's not clear to me how much of the upgrade in the cash flow outlook is a result of a more bullish macro view versus an underlying volume and margin increase. So could you help potentially to disaggregate what percentage of the increase is because you're more bullish versus underlying value add? ... And finally, and sorry to ask three, but I may have missed this, but what exactly is your new oil growth rate? You guide it to 1 and— you had guided to 1.5%-2% oil compound is 27, and now we're back to 2, 2%-3% total oil and gas. And within that, I guess you could help, we get— I'm getting a lot of questions on this myself, what are the quantum of barrels that you expect from Namibia? As I think the jury is out on how scalable it is, especially given the mixed success on exploration to date. Thank you. Hola, many questions for one. Maybe we missed something. No, we again, we told you that we continue to sanction projects at $50 per barrel. We keep the discipline. In this present market, we thought there was a long discussion. Do we put 70, 80? Okay, we don't. It would have been a strange presentation in a market which clearly today is more at 95 to come with $50 or $60. You would have think that we are super cautious. So we don't tell you that we have a long-term view of $80, but we see a lot of indication, which I think we are clearly supported by Helle presentation, why today we are, yes, we are more bullish because honestly, my view is that, OPEC plus has taken the control of the market, you know? And, and but we see these guys, they don't want to, they, they like to have a high oil price, you know? Because the dynamic on the supply side is not set so clear, and particular in the shale oil, we see today a strong discipline compared to the previous period. So that's why we, we think that we have entered into a, a world where the oil price might be higher. Having said that, we keep a discipline on our investments and the allocation of NOR, so we, we sanction the project. So that's the answer. Now, on the cash flow outlook, it be clear, you have the figure, Christian. All the figures were given to you. All the $6 billion or the $3 billion, what one of you seems to think in, in not sufficient, were clearly without impact of oil price, and it's the same, it's the same nominal, price deck. So, and so when we, in a slide, I think the slide at the end of my own part, which was a slide number, I don't remember, 23, you see a more than $10 billion. You can clearly, see that 6 or 7, because we started from 21. So $7 billion is a volume growth, and the $3 billion come from the price deck, which was different in that slide. So again, the underlying value add for 2023 to 2026 is $6 billion, as I explained you in the one of my final slide. Oil growth rate, you can calculate it from the slide with your double, with your, with your thumb, if you want. And Namibia, let's wait a little more. You know, I told you there will be a little... Let's see, it's not finished. Don't jump too quickly into the conclusion. I gave you some indication, positive indication, but today it's premature because I could be either, again, conservative, if I answer to you, and then you will criticize us, or too optimistic. So let's, let's drill the well, let's make the test. Yeah, Ella wants to add something. Yes, Christian. I, since you mentioned the IEA, I just want to tell everybody to read carefully the statements that come out of the IEA, and especially, Fatih. Because when, when Fatih says or the IEA says, oil demand is going to peak in this decade, there is also in the sentence, not always, repeated by the press, if all the countries deliver their targets by 2030 and 2050. It's a big if. And secondly, you may have noticed that very recently, he also adds that even if demand were to peak, it would peak at a slower-- it would decline after that at a slower rate than the natural decline of the oil fields. So now he also says: Mind you, we will continue to need more oil and gas projects, which is a way of saying, careful here on supply. Okay? So I think it's important to go back to everything he says and not just the headlines that the press uses. Okay, we get back. Biraj now, please. First, yeah. Hi there. Thanks. It's Biraj Borkhataria from RBC. First question's on dividend growth. So you're pointing to 2%-3% volume growth in the upstream, plus it looks like there's some underlying margin improvement. And then you're buying back, you know, at this point, 5%-6% of your shares. Plus, as you get to the end of the plan, the integrated power business becomes less of a drag on free cash flow. So I would have thought, you know, is it reasonable to expect dividend growth in the region of 10% in the similar environment, which is higher than the, what you name checked, about 6%-7%? So I just want to get a sense check of how you're thinking about medium-term dividend growth. Second question, just so similar to last year, you presented everything excluding Russia in terms of the cash flow targets. Could you just clarify for 2023 what you're expecting to receive from the Novatek dividend, if at all, or the Yamal dividend? Thank you. On Russia, as you know, most of the cash flow is coming from the long-term contract that we got, which is not a Russian asset, but it's linked to a Russian asset, but it's a European contract, I would say. So that's the core of it, and it works. We only with the strictly with the long-term volume, which we are committed, not much, because we stopped all the short-term, but it's a profitable business as it was before, I think. For Novatek dividend, we received nothing for the time being. Should be clear in 2023 up to date, so the answer is quite easy. And then, on the first one, no, I will not answer your question. I have given to you some guidance. One is more than 40% of distribution. I told you that all when we buy back shares, we cancel the shares, and it will, of course, be replicated in the dividend the year after. Then let the board decide what will be what you want to share between dividend and buyback. I mentioned during my speech, I think about 7% last year is might be for next year again. But let's keep this, I would say, this flexibility between dividend buyback to the board. I don't want to overconstrain everything. Last year, I remind you that we tried a year in 2018 to announce a future growth of the dividend, and then the share went down. So since that day, I'm super cautious about that. Today, I'm happy the share is going up because we announced a global, higher premium, distribution policy, which I think is good. So I won't want to over constrain the system, and let's keep some flexibility. Let's keep maybe Yeah ... question online. No, no, no, no. Yeah? Continue. I will tell you when we go online, because- Uh I see many hands raised here. Okay, Alastair decides to change. Hi, Alastair Syme, Citi. Patrick, can you talk about, you, you touched on it in your presentation about the retail business, just the strategy for it, 'cause you, you did the deal earlier this year with Kuusitoimisto. You know, you sold part of the business, you still got France. So, you know, what, what's the sort of the pathway forward? No, we are fine with France. You know, we have a leading position. Again, in these European countries where Germany and Netherlands and half of Belgium, we had limited market share. A good offer on the table, 15 times on net cash flow. So, why should we refuse the offer? We don't... We see a limited, limited synergy between these networks and EV, in fact. EV, for us, as we said, we want to concentrate on highways and city hubs. We have plenty of stations which are not fitting with these two definitions, where we don't see a much, a very strong EV business, because don't forget that people will charge in many provincial cities, they will charge at home, in fact, or at office. We have to be careful in the impact on European networks of this transition going to EVs, which by 2035 will become even mandatory. That's why we had a good opportunity. We kept, and the French position is strong by itself. I think it's better to control the pricing policy in France, considering where our headquarters are located, so we are fine. So we have, I think today, and Stéphane done it in the name of Thierry, which is there, because we don't want to have a comprehensive view, and Stéphane explained where we might have some synergies. We have defined what we want to do in the EV mobility. And, again, highways, where we have taken in France for quite a number, 40%, I think, of the concession already. So we are even stronger on EV charging on highways and motorways rather than on oil today. And city hubs, where we are kind of really developing an aggressive strategy for Europe. I should add that there is a segment in the B2B, which is, of course, trucking, trucks. We have a very strong asset, which is what we call the, I don't remember the name. Eisenkat ... Eisenkat 24. I think, covering Europe from Poland to Portugal for... And that we intend to accelerate also our high-power charging for trucks in the future on these networks. So that's a key part of it. So that's the reason why, so French position is strong, we'll keep it. Okay, so maybe, Jason? Hi, Jason Gabelman from TD Cowen. Thanks for the presentation. Two questions. First, on the, on the projects you list on slide 13, Iraq and Mozambique are, I think, two large contributors to cash flow growth, maybe $1 billion of cash flow each, and some kind of fits and starts on both of those. So could you just, one, confirm that it's, it's still about $1 billion of cash flow that you would expect from each of those projects? And, address any uncertainties, in both of those, given, given the fits and starts and the confidence that, they're gonna start up by 2028. Oh, Iraq, will start for sure. We already produce in Iraq. So because the contract in Iraq, as you know, we have taken immediately from since August 2016 access to a production of an existing thing. We need to grow it now in order to finance. So in fact, the exposure to Iraq in terms of financing, in particular, because we take it at a time where the price of oil is $90, which was not really the assumption when we negotiated three years ago. So we have access, now we will grow it, so we have already some cash flows coming from Iraq. Situation, if we have decided the situation in Basra area, is, our security teams have, of course, made a full audit of it, are under control, and we are-... I think we can do it like others, by the way. We are not the only one to operate in Iraq, you know, for many years. So it's a matter of discipline, of security, of course, and this is of primary importance for us. But I think, and we have been very welcome by the Basra Oil Company and all the stakeholders. It's considered today in Iraq, you know, as a major project, so we have a strong support of many, many, of all stakeholders, in fact, in Iraq. Because some other companies decided to leave, so we came and gave us, of course, the opportunity to have a different contract than the one which we signed before. So on Iraq, yes, we are conscious of the political situation, but we take all measures to be able to. We don't face at all the same type of uncertainty than in Mozambique. In Mozambique, you know, we are under force majeure since 2021, I think. Situation has clearly improved because the governmental forces, supported by other countries, in particular Rwanda, have taken back the control of the situation in Cabo Delgado. We make a number of audits which are satisfactory, and our objective is to restart the project before year end. Today, in fact, we still have one major, I would say, which is a relationship with our contractors, because some of the contractors would like to benefit from the situation to increase their costs. We disagree. So we have some negotiation, including to re-tendering some of the package in order to mend, to control the cost of the project, but we'll have clarity of that in the coming months. Yes, I would say security, but if we restart, it's because we came to the conclusion that we don't want to restart to stop again, be clear. So we are able to execute the project fully. And it's not only shared by TotalEnergies, but by our partners as well. So the improvement of the situation is strong enough, and in order to be able to remobilize contractors and to deploy, develop the project. Great. My follow-up, just on the underlying cash flow growth, that $6 billion, I was wondering if there's any consideration for LNG trading strength in 2023. So either do you expect that to fall off and normalize moving forward, and that's embedded in the $6 billion of cash flow growth? Or conversely, because LNG trading has been so strong, do you expect that to support the LNG business moving forward? Thanks. Again, LNG trading was very strong, in fact, in 2022, to be clear, very clear. I think the 2023 already has been normalized somewhere. I don't. I'm speaking about the under the control of Stéphane. So we consider that for the future, we could be able to... So compared to 2022, there was a, you can see in the figures that we report integrated LNG, so you can see that, we are landing on something which is probably more normal. But in fact, this trading activity is linked to volatility, not on the absolute term. You know, what is, traders, they love volatility. Volatility is lower this year than it was, but we don't see—we think, honestly, you've seen you've seen this summer, fear of strike in Australia, and poof, the markets are taking 30% or 40% in a few days. So the volatility, my view is that the LNG markets for the year to come, in the situation which was described by Helle, where you have more demand than a strong supply, so a constrained supply, is a fragile market, so volatility might be there, but lower than in 2022. So we normalize that at the level of 2023 for the future years, and that's a target for trading teams. But there is no $6 billion in additional trading activity. So this $6 billion, again, just to clarify, these are the assets. You know, the assets by themselves, only the assets, without optimizing, et cetera, will deliver, in the same environment, an additional $6 billion or $3 billion for the oil and gas asset. What can be done around the assets of the optimization is not taken into account there. Okay? Thanks. Maybe we are conservative from this point of view. I take Oswald maybe, and then I come back in the room. Okay, so we take Oswald online. Oswald, if you are on there? Yeah, thank you very much, and apologies for, for not being there as well. We have our, we have our annual conference this, today and tomorrow. But, firstly, if I could ask, I, I loved slide 33, the levers to profitability in integrated power and the topic around 12% returns. And the comment there, you have about 10% OpEx and CapEx, below the market levels and the 1% efficiency above. I, I think that's the first time you've explicitly stated those, and obviously, they're quite critical to internal rates of return calculation. So I was wondering if you could elaborate, on, on those numbers. Are you starting to lock in those types of savings already? Of course, we know there's a smaller group of suppliers on the other side who are under some duress at the moment, and whether we can really expect those types of savings to be locked in here. That's the first question. Thank you. Secondly, perhaps just following up on that last question on LNG and trading. I mean, this year, we could probably have 65-70 million tons of LNG sanctions, which would be a record. And there's a lot of portfolio players lifting a lot of that from the U.S., and a lot of them will be seeking to build out trading businesses and optimization. So it's kind of linked, but, you know, is there any threat here?... that some of these players start to just take some of these, you know, arbitrage divergent opportunities through the medium term from the Total portfolio? Thank you. No, so the second question is, welcome to the club, and they have to learn before to be able to do what we do. So on the first question, but, Stéphane, you can elaborate both questions if you want. I give you the floor for the first, and if you want to continue the second one. No, on the first question, what we've done first was to understand where we are and start the benchmarking exercise. What you figure out is what is common sense in the refining and chemical with Solomon, Solomon Index, for example, is not necessarily the case yet on renewable, it's starting. And we believe that there is a lot to learn on benchmarking, standardizing, and so on. So yes, the 10% CapEx and OpEx is based on what we learned from that exercise of benchmarking and on the assessment of already CapEx and OpEx savings that we have identified, and we have started to catch some of them. I mentioned the one on capacity reservation agreement with solar supplier. Now, obviously, it's going to take a few years to fully get to that. But I've got project manager action plan identify. We've gone through the CapEx and OpEx cutting exercise. I've gone personally through it in 2014 in oil and gas. We know how to do it, and we are going to do exactly the same thing because it's the same way it's going to work. That's one. On the second aspect, on LNG trading, well, yes, you have a U.S. player, but arbitrage is about getting a global portfolio with global shipping, regas, capacity, plants, both in Middle East, Asia, and the U.S., if you really want able to extract the maximum value of all that. And I don't buy the idea that if you are just a player in the U.S., you can do that. It's that's clearly one I consider of the strengths. And if you look at one thing, for example, the ability we had in 2002 to divert volume coming from the U.S. that were supposed to go in Asia, and that at the end of the day, went to Europe. You look at the conversion ratio we get, we were by far the first one to be able to do that. Because the gas capacities and all the midstream assets are important when you want to play this type of activity. Okay, Lucas? Lucas. I see you in front of me raising your hand, so I will not wait for the. Well, we'll go on the table behind. Yeah, Patrick, thanks very much. So it's Lucas Herrmann at BNPX. And, two, if I might. The first goes back to the return question that, or the return observation that, Oswald made a moment ago on the renewable power build, the integrated power business. Historically, you talked about 10% return on equity. You're now talking, you know, 12% return on capital employed. I would have thought the return on equity would actually be even higher than 12%, if that's the way. But question one is, is really, Stefan, whether there are particular... Is it everything you've said that drives that improvement? It is quite material. And can you just put the free cash comment in the context of EBITDA? The old target used to be around EUR 3.5-4 billion of EBITDA. Now, you're talking around free cash or cash flow from operations, so just to contextualize, contextualize the two. And the second, more broadly on CapEx, this has been a big year for divestments. When I look at everything that you're doing in LNG, you know, in the upstream, in the renewable power business, you know, we're going through a pretty intensive organic growth phase in many respects. You're high-grading the portfolio. How should we be thinking about, you know, divestments going forward, Patrick, in terms of absolute scale? And when you talk the cash flow numbers and the cash flow growth, how much cash flow will you look to cede from businesses that you're likely to divest over the five-year period as you high-grade, for want of a better phrase, you know, the upstream portfolio in particular? Can you take the first question? Yeah, yeah, on the first question, yes, the answer is yes. The 12% return on capital is clearly taking into account the four levels that I've mentioned. And globally, you can say that one-third of the improvement is going to come from OpEx, CapEx, one-third from selling better, and one-third from the portfolio optimization. That's one. Then, obviously, the question on return on equity depends on the cost of debt, so which is moving. And at the end of the day, we choose to communicate on return on capital, because at the end of the day, that's the metric we use on oil and gas and to be consistent. And actually, that's what we have started to publish in the beginning of the year. That's one. Second, the same way as now we publish a cash flow from operation, we continue to fix target on cash flow for operation. If I look at the ratio between EBITDA and cash flow for operation, the ratio we had in 2022 is pretty much the same in 2028. So we go from 2-4 on one side, which is doubling the EBITDA. You can expect the same thing on, on proportional EBITDA. ... on the divestment, in our plan, the divestment acquisitions are more or less equal on the next five years. So when we acquire, we divest. Don't forget that we have some funds coming from the divestment policy from Stéphane portfolio as we divest 50% of renewable assets. So more we grow this portfolio, the more we have some proceeds from these renewable sale divestments, which can feed the acquisition part. So again, the target we gave you does not, are just with our existing portfolio. There is no further acquisition beyond what the target is of additional cash flow. It is the asset base that we have today, which will deliver an additional $6 billion in five years. Okay? Luca? Pardon, no, Renaud. Yeah, Paul, go ahead. Paul, on the other side, please. Thank you. Paul Cheng, Scotiabank. 2 questions. First, Patrick, or maybe it's Nicolas. Since you finished the last appraisal well in Suriname, you stopped drilling any exploration well, for the remaining of the years. Is there any implication? Is it you just don't see the opportunity on further exploration? Or, I mean, any reason, or we're just reading too much on that? On the second question is on the integrated power. If we assume the, higher interest rate environment is here to stay for the next several years, is there, in any shape or form, going to change your business model or lead to a modification? And also maybe for Stefan, that in your presentation, you say you expect a 10%, or you aim for a 10% lower OpEx and CapEx, comparing to the market average. So can you tell us that what is the current position? Are you at the market average or you are above the market average by 10%-20%? Thank you. Yeah, if we want some improvements because we are not yet there, so be clear. So this is what. No, there was a time when we grow, we, we grow quickly that business in five years, so now we have a large portfolio, so we can begin to match benchmark. We've done it for France, we've done it from some countries. We need to expand it. And clearly, we consider, because it was, this portfolio has been built from inorganic, organic, small developers, so there is a huge action, what we call, or strengthening the industrialization of renewables, and this is the next. And we, we just, as Stefan just reorganized its business unit, of renewables in order to specify it. Everybody was concentrating on the development, business development. Now we need to teams dedicated to projects and teams dedicated to operations. Exactly what we've done in oil and gas historically. So this is what the model is. And so we expect, this is why we think this 10%, minus 10, minus 10 are achievable in order to industrialize again the way we produce and we built all these projects. On Suriname, the key. I mean, I mean, let's be clear, most of all, we drilled 15 wells or 14? Fourteen. 14 wells. So we have honestly covered quite a lot of large targets. There are some, still some marginal, there are some targets, but which, in fact, which will be tied back, future tie backs to the development we envisage. So they are not very large, but which might which will extend the plateau of this initial development. But so we don't need to rush to explore today to put them into production in 7 or 8 years. So the priority now is to put into production these, what we have discovered, to keep the flexibility in the way we design the development in order to be able to make some tie backs. So for me, it's more extending the plateau of these 200,000 barrel per day rather than add new discoveries. Then, to complete, in the north of the block, we have, some few large prospects, but everything which has been drilled in the north, either on our block or on the adjacent block, has been negative. So there is a certain point where I consider, we consider that it's- we have, we have a good understanding of what happened, so exploration is no more priority. It does not mean that there is not yet targets, smaller targets, more tiebacks for the future. Okay? But the oil part, when there is a gas part, gas prone discoveries on the, on the, western part of the block, where the question is, how to monetize all that? And monetization of the gas is not very obvious in that part of the world. But we'll work on it. Priority today is to produce oil and to deliver cash flows, to monetize the exploration. We have one question there, please. Great, thanks. Ryan Todd at Piper Sandler. Maybe a couple quick ones. One, on your gas and power strategy, as we think about your gas and power strategy, you've got a constructive long-term view on natural gas. You've got a constructive long-term view on power pricing. I think that underpins part of your investments here. How are those necessarily linked in a way? Do you view the linkage of natural gas prices and power prices as linked in any way? And as you think about your how do you think about risk in those markets longer term, your willingness to take 30% merchant exposure if how much of the project economics depend on that merchant exposure over the longer term, as you think about managing those businesses over time? Then maybe as a second question, you talked about how you've, you've been pretty active in the acquisition market. Most of your acquisitions have been on, on renewable and low carbon areas. Do you have, you know, going forward, is there appetite for oil and gas focused acquisitions as well, and how would you characterize the, you know, kind of market opportunities there? The second point is not true. When we will provide you the data. In fact, we have acquired this year out of $6 billion, it's more than $3 billion are in oil and gas, in fact. So no, it's not true. It's, maybe you have the feeling, but in fact, when you acquired Abu Dhabi, when you acquired positions in, We did Brazil. In Qatar. Qatar. It's not far. So we, in fact, we are acquiring more in Brazil before, so in fact, we are spending... We continue to develop oil and gas, primary focus. Again, there are two pillars, they are equivalent, and one is bigger than the other one. So, so we continue. We have appetite, we have appetite. We need—we already said several times by growing our business, LNG business in the U.S., we're required to consolidate the upstream, when that one, at a certain point. So we are permanently looking to opportunities in both aspects. Again, when price of oil are quite high, it's more complex to have access to good opportunities in the upstream part, but it's not very contrasting equal today, so but we'll look at it. On the first one, there are links somewhere in Europe, but at the CO2 price. You know, in Europe, the power price, marginal power price is done by natural gas plus CO2, not only by gas. And the CO2 market, CO2 is important. Do you want to... Honestly, if we want to keep merchant exposure, it's not only a risk, it's an opportunity. It's because we like to have some upside as well. So the, in fact, what we want, just want to do is to use, contrary to utilities which have high debt, we don't have a debt, so we can take this type, exactly what we've done in LNG. We can take a risk, we cover part of our risk, and then we, we keep open to the market a certain amount of our, of capacities, of our productions. We are resilient. This is why it's very important, like Stefan explained, to have a quality portfolio from an OpEx point of view, like the $5 per barrel on the oil and gas side, in order to be resilient when the market is lower, but to capture the upside when price is going up. It's the same philosophy. In electricity, obviously, it's more volatile because you have a daily volatility, a weekly one, and it's more volatile. So this volatility needs to be more, have more sophisticated tools, and also to have a flexible assets in order to be able, or storage capacities, in order to be able to capture this volatility. So that's the idea. So it's more fundamentally for us, keeping part of the upside and not... What we don't want at all is to have a secured, warranted business with PPAs, you know, that's not what we want to cover because it's not what our investors are expecting. Other comments on natural gas and price link that you would like to add? Unless it's the natural gas price will depend as well on different markets. In Europe, clearly now the price will be driven by U.S. LNG import. European Russian gas has disappeared, so that's the key driver on it. This might impact other world market, but the power prices are more subject to local regulations after. So you don't have a direct link necessarily between the world, a worldwide market, a gas market, and the local price market. You want to add something? Yeah, perhaps just one comment to what you said, Patrick. It's clear that in Europe, power prices are linked to natural gas and CO2. And following the crisis last year, natural gas prices in Europe now are very much connected to LNG. And by the way, that's one of our competitive advantages versus the players in Europe, is that we have a deep understanding of the LNG market, hence potentially the dynamic of the power market, which I believe is clearly for our integrated power business as well a nice competitive advantage we have because of that connection. There was a long discussion internally if we should split the teams in charge of trading gas and trading electricity, as there is electricity, but I would say the medium long term is next, but the short term is different. We decided to split, but locally, we are localized, the office is in Geneva, next to each other, to exchange all, to keep all this knowledge. So even if now we have two different business units, because we need to grow the power trading in order to cope with all this, I would say, short-term volatility, which is quite an interesting part of capturing. Again, when you have intermittencies and flexible capacities, you need to optimize the systems. Okay, so we have Giacomo now? Okay. Giacomo, and then we'll take Lydia, so that Lydia can be prepared herself. Thank you, and Giacomo Romeo at Jefferies. Patrick, you talked about the importance of having somewhat predictable shareholder returns, and obviously, you have moved from a range distribution policy to a open, somewhat more open-ended distribution policy. I'm just thinking in weaker macro environment, to what extent do you feel comfortable to increase these policy, CFFO distributions in order to avoid being excessively procyclical in your share, in your shareholder distributions? And somewhat related to that, you highlighted $2 billion downwards CapEx flexibility, and just thinking at what oil price would you start considering flexing down your CapEx? Okay. $50. Quite easy. No? More or less. I'm under your control, so, yeah, but that's the idea. Okay. 50 is a COVID. I mean, what happens? You know, you need to have flexibility when you- By the way, during the COVID, that we were able to play CapEx. But, uh- At the time. Okay, so 50. The first one, I remember the same question last year when we gave a range, people immediately say: Can you go beyond the upper limit? And now we give no range, and why don't you have a range? So I'm, I'm a little perturbed, sort of disturbed by your question. No, but again, it's not procyclical, it's just that, again, we're keeping 40%, above 40%, you can do it. There's a big difference, the balance sheet, again, we can... It was your question before. One of you asked me: Can you go beyond your CFFO in case you need it to maintain your distribution? The answer is yes. Maybe I didn't capture fully your question. Yes. I think the opening makes sense. So just questioning on up to what level you feel comfortable stretching that. Above forty is okay, and then it depends of the situation. But again, the balances allow us to maintain the distribution policy. By the way, I remind you that this company maintain its dividend during the COVID, unlike others, you know, we maintain. So we can be quite stubborn in maintaining this distribution policy through cycle, using the balance sheet again, if we need. Lydia? Lydia, and then I'm coming back. Lydia. Lydia online, if we can get Lydia. Oh, can you hear me? Yeah. Yes. Can you hear me? Yes. Hi. Good afternoon, everybody, and sorry that I can't be there today. But even from this distance, the message from the day seems to be one of growth, both on oil and gas and integrated power. How long do you see that growth being able to last? Is it that idea that as energy demand continues to grow globally, Total should be, or Total Energy should be able to grow faster than kind of overall energy demand, and that's their growing business? The second one was then just coming back to the 12% return on capital on power. I'm sorry if I missed this, but can you go through how to get to that number, the interest rates, the power prices, just because in this interest rate environment, that does seem high. And then one very final question, if I could. Everything you've said, Patrick, sound brilliant. What are you worried about? Where, where are the things that kind of could go wrong that we need to watch for? Can I just... Is it inflation, that sort of thing? Thank you. It's probably the period of since I'm CEO, but I'm less worried than some other periods, to be honest. I think the strategy is in place, markets are okay, so of course, something will happen. I don't know what, but, we'll have to look at it. The macro environment is a little worrying somewhere because we have a sort of disconnect between financial markets and all this interest rate. And, in fact, fundamentally, first time in economic history where we have to adapt very quickly to a higher interest rate and higher inflation, which probably has never happened at this pace. You know, suddenly we've seen everything moving, so we don't. I'm not sure we have understood fully the implication of, in terms of macro, of such a shock of interest rate and inflation, because when you look to the economic history, it was not very frequent to see such a shock. So that's something that we need to monitor. But having said that, the company itself, TotalEnergies, with again, our balance sheet and all the markets on which we are, I'm comfortable to be able to navigate, even if there are some hiccups which are in front of us, I would say, so I'm comfortable. The growth lasting on both oil and gas, integrated power, there is a market on one side and there is TotalEnergies on the other side. Again, I think, it's really, my view is that we have been able, again, thanks to all our, the strategy we deployed during the years to build a rich portfolio of projects, and we intend to continue to build it, even if for the next years, as I think Nicholas' message was clear, the focus will be more on delivering all that and focusing on execution, because we have been quite active to get access to this project. Now we need to deliver them in different environments, including the fact that we go to new countries, where we need to be able to establish a position. On integrated power, it's an arbitration, of course, between growth and profitability at a certain point, you know? That's why we, our view with Stefan is clear that with $4 billion per year CapEx, it's okay. It's, it's fine. We will not continue to grow it. We want to keep it as it is. We think it's the right level, to be able to, to grow to 100 TWh, more than 100 TWh of production, and we intend to maintain that to- because it's in business where, of course, the leverage is important and the interest rate is part of the equation, which might, might have an impact, but it's, I think it's the right place to do it. On oil and gas, it's, there is a market on one side. We continue to dynamic and our capacity to identify new opportunities. But even when we defined a few years ago a playing field, which is low cost, low emission, what you can observe is that we have been able to inside this playing field, even if we stop or we divest some assets, like in oil sands, because they don't fit with our long-term perspective, we are able to deliver growth, so that's our view. I would say on the longer term, the question, the key question for LNG and natural gas will be, can we really displace coal like everybody thinks? Or we'll have a world of renewable and coal, which in countries which is not good for climate, but that's an option which we could see in some countries. 12% of do we get to that number? I would say we are already at 10, so we have to go from 10 to 12, but it's again, the target is what we set. I think we explained the philosophy is that we want that business to be compatible with the oil and gas business at $60 per barrel. And when we look with the Stéphane teams to what is it achievable? I think it is achievable. I remember when I became president for refining and chemicals, the return was 6%. I had exactly that 12% target. Today, Bernard is at 18%, so you know, it's just a question I think of having the focus not only on growth but also on profitability. And maybe you have additional views, Stéphane? No, but I, actually, to turn the 6 on the 18, at that time, you were president of Refining and Chemicals. It was really a bottom-up approach, where you look at every stone and, and work on it, and, that's exactly what we are going to do. To apply. Okay. So we- Maybe we could take somebody here. Yeah, Duke, there. Duke, there are less hands raised, so Irene, you can prepare yourself for the next question. Thank you, Patrick. It's Doug Leggate from Bank of America. Thanks for taking my questions. So I want to go back to Suriname, and one of the comments you made about the payback. You said the payback is about three years of $60 oil. That would put your share at about $1.5 billion in 2028. Your E&P growth is $3 billion. How much of that $1.5 billion have you included in your $3 billion growth? I think the startup is in 2028. Does not mean you have a full year in 2028. Yeah. That's part of the equation to somebody. I was thinking that, in fact, Suriname, the full year is not 28, it's 29. Right. Sorry to have cut 5 years, but next year, we'll have a figure. So you, your figure is right, but including the carry, but it's not 28, it's 29. So my follow-up is on that 2028. Three years of exploration, concept selection is already done. Typically, FPSOs are ordered well ahead of time, and you've given yourselves five years to first oil. Are you being conservative on the timing? We need. We know we just defined the concept is done, but the front-end engineering will start, and we need to make the tenders, and if we can accelerate, we'll do it. We are looking to another scheme to go quicker. But that means that it's a matter of direct negotiation on some specific concept. We'll see if it can go quicker. But honestly, we are not so conservative. We are at a point, we just have made the appraisal, we set the target, we know we need to develop engineering for six months. My teams would be very, they know we set them end 2024. And I meet the teams, we are not so keen on end 2024. I think, we told them, "Okay, hurry up, please." No, but there are, there, there is one way maybe to go quicker, but we have to, to understand exactly what to do. So 28 is fine. You know, we need, again, a year to go to the FID, just because the tender of FPSO of this size, it takes 6 months, more or less. So engineering, 9 months, 6 months for tender, and then execution, it takes more or less at least 4 years, 3, 4 to, 3.5 to 4 years. If we can do quicker, we'll do it, don't worry. We are, we are driven by time. We know time is money, but... It's big FPSO, compared to what was planned, because when people were speaking there before, I know my partner was speaking a little too much. We are the operator, by the way. They should not forget it from time to time, and we are in charge. No, but I mean, what they had in mind was a smaller development. We are not at 160 or 150. We decided to go to 200 because we have the potential for 200, and because it will give more flexibility for the tiebacks in the future that I mentioned in terms of potential exploration around. So 200 is quite a big business. Okay, and as you, Stefan... Nicola said, we want to get zero flaring, so we need to reinject, so we need quite a large gas capacity on board in order because there is of course, it's an oil development, but, you know, in Suriname, we are struggling with the gas-oil ratio. So we identify this pool of oil where lower gas-oil ratio, but still, you have gas to manage. So that makes also things. When people think you can find a FPSO on a, in a supermarket with this type of equipment, not sure. No, with gas, so it's a full. It's quite a big, a big, installation that we need to build. Okay, let's take Irene online. Please, Irene, go ahead. Thank you very much. Irene Himona from Société Générale. I had two questions, both on power. So first of all, on your concept of industrializing integrated power, you referred briefly to it, but if you can just expand a little bit on the components. I mean, it sounds like having a coherent process and organization, but what else is it in practice? Will you, will you look for project standardization in each technology hub, perhaps, or each region? Will, will you aim to sign long-term framework agreements with contractors as you do in oil and gas? And by the way, related question, is this, do you think, a competitive advantage you derive from oil and gas, or is it something the big players already do? And then secondly, still in integrated power, you refer to maximizing value by utilizing the trading power which you are building. I struggle a little bit with the concept because, because as you said, electricity is a global business. With oil and gas, you know, you load it on tankers, you send it off to the most profitable market. What does trading actually mean in practice for the integrated power business? Thank you. Stefan, you can take the second one. On the first one, just well, honestly, I think the best might have some big competitor who are doing it, one in is in the US, by the way. NextEra, I think, is a good example of when you try to strengthen renewable industrialization, it goes for digital. By the way, you can in industry, in renewables, you can have some large digital platform where you you command your all assets, you follow them in order to maximize the maintenance, lowering the cost, human cost, labor cost. So there is a lot of things. Size is a way, again, scale is a way to reduce to reduce your OpEx. On the CapEx, I think Stefan commented during his presentation, the idea to have a certain limited number of solar development, solar design, which we have now optimized. So again, you have to understand, Irene, as well, that today we publish these results, and we are today at around 10% of return on capital employed, helped by the market. But, and we have done... We didn't work on that part, in fact, until now, because we have more. And so to Stefan, as he narrated with his team, some a number of developments around the world. So this idea of industrializing for us is clearly an added value which will come in front of us, and joining the best of the class, best-in-class companies doing that for years, will give us additional returns and profitability. This is the fundamental idea, that we want to, to deliver. And again, working in the same way that we are doing this in, in other businesses. On the trading, you can explain why integrated power can make money from trading, with even if it's, local markets. So it's, it's true that, integrated, power trading is, is to some extent, a local market. Even if, when you look at Europe, it's clear that, you can't trade France alone. You are going to trade France, Germany, Spain, the Nordics, and even a bit Switzerland and Italy together, at least for the three months liquidity period. And here, clearly, what are the opportunity of arbitrage? Trading powers is trading the d- it's trading the difference first between, gas, power and CO2, especially in Europe, because power price are made or the clean spark spread of, of CCGT. So that's one aspect of trading. Just take a small example to, to try to elaborate. If you look at the power dynamics between France and Germany, you have to understand the spread of gas price between France and Germany, which has done with a lot of volatility in 2022, and then the clean spark spread of CCGT in France and Germany. And every side, every single of that is linked. And here, you have a lot of value that can be done because of our arbitrage capacity, especially if you are in all markets. Just talking about flexible assets, if then I look at the intermittent asset, it's clear that on one side you have something which is very depending on meteo and on, over the three months, but at the same time, you sell firm power on the market. So there is a big risk managing that position and a huge spread between those two. Depending on your capacity to blend the right asset and then to have the right coverage thanks to flexible asset, you can as well extract a lot of value. And that is not only at the local scale, but at the European scale. You can look, it's quite funny because there is clearly an anticorrelation, for example, between wind on the eastern part of Europe and solar on the western part of Europe, that today you can, for example, arbitrage. Well, that level of complexity that we are starting to address and quite successfully, actually, in last year and this year. And then if I compare to the US, in the US, it's even, it's even, more complex because we don't have Zonal System but Nodal System. So if you just take ERCOT, for example, trading between trading east and west, you have plenty as well of arbitrage. Okay, let's take in the room, maybe. Yeah. Thank you. We have Kim there, I see. Hi. And then we'll take Martin on the— Okay ... on the audio. Kim, please. Hi. Yeah, it's Kim Fustier from HSBC. Just two quick clarification questions, if I may. Just on slide 23, there's a divergence in trajectories between oil production on the one hand, which is growing, and oil sales, which are declining. I just wanted to clarify, is this decline coming from the sale of assets to Kustar, which has already been announced, or does this assume future asset disposals, which, you know, looks like they might be needed for you to hit your Scope 3 targets on the oil side? My second follow-up is in Integrated Power. You talked about utilizing your fortress balance sheets, and I think you previously guided to 70% project financing and 30% equity. Could you quantify where this mix could go if you're planning to use more equity? As a result, could this impact your CapEx guidance, i.e., could this move to more than $4 billion a year? Thank you. This guidance has been given to you for the renewable part, which I think is still valid. So we have doesn't change the guidance of 30% equity, 70% project on the renewable part. Which means that when we put $4 billion, in fact, in our CapEx, we finance more or less $10 billion of projects, in fact. So to be clear, if I made the math. No, I think it's clear. We didn't change. We did not elaborate this year about the refining strategy because it didn't change. We announced you that we were this is still through I would say four years. We were clearly producing 1.4 million barrels of oil per day and selling in full refining and marketing more than 2 billion barrels of oil per day. We decided that we want to realign, to integrate our oil because of the evolution, potentially, of the market. So in fact, we are selling less just because we are... That's true, that we have, by the way, there is an impact, obviously, of the divestments of some retail network. But there is also the idea that we will realign, and we will continue, as it was explained on one side, transitioning European refining assets from Bernard. That means moving from less oil sales, less oil product sales, to more stuff. But you know, when you transition a refinery, we've done La Mède, we've done Grandpuits. We'll plan to do another one every five years, more or less, in order to cope with the evolution of the European markets. But of course, we transform, we sell less oil products and more, I would say, low-carbon molecules. So that's the idea. So there is no change in that chart. It is the same. At the end, the idea is fundamentally to produce 1.4, 1.5, and to sell 1.4, 1.5. But it's more coming from the transitioning of our- We are in downstream, quite exposed to the European market, which is the one which will transition first according to this 2035 deadline. So we need to prepare ourselves to face such a transition in order to, I would say, be less sensible to the downstream oil market. But to benefit at the same time, because Europe is offering to us new opportunities in terms of downstream market, like the sustainable aviation fuel, like the EV mobility, so to rebalance or allocate our businesses in the downstream. But the idea, so no change. And honestly, it's not driven by Scope 3. Scope 3 is a consequence, huh? It's not a strategy. Don't... Never misunderstand me. At the end, this is a consequence of the strategy we think is good for the company, because we need, we know that this downstream assets are heavy assets, socially as well, and we prefer to plan the transition rather than to, to be, in a war and to what do we do in 2035. So it's better to plan it than to have a trajectory. And again, we can leverage these assets in order to, to be, to take positions on a more, long-term market, like the sustainable efficient fuel one. We go to Martin? Yeah. Hi. Hello. I wanted to ask a question about my favorite topic, which is refining, which is what you just started. So, I think my question falls on quite nicely. So, I've noted on one of the slides that the plan to 2028 is based on an assumed refining margin in Europe of $35 a ton, and I was wondering if you could say a few words about the risks around that figure. The reason for asking, of course, is that refining margins at the moment are very, very much higher than that. And also, if you look at forward curves for refined products, forward refining margins would suggest a higher number than that. Given the amount of refining capacity in Total, of course, every $1 per barrel in the refining margin is still $500 million of cash flow, so it's not entirely unimportant either. Specifically in the Atlantic Basin, the market looks pretty tight to me. We've only closed refineries so far, and oil demand is broadly flat. So particularly in the area where you are, actually, you could make the argument that the risks around that are quite sort of skewed to the upside. But I was wondering what you thought of that argument. Well, let's see. Refining margin to be okay, today, they are around $100 per ton, but take it. I will not put my money, but it will remain at $100 per ton, maybe for... So by the way, the reason why do we have high margins today, we have. It's clearly a consequence of this Russian ban, in fact, in fact, somewhere. There are many consequences of Russian, but strangely, when the ban came into action in March, we see nothing on diesel. We begin to see it because in the ban was announced for March, so everybody stored the Russian diesel before, so there was no immediate impact. We begin to see that today because there are several impacts. One is that, crude oil, you know, and it's also a result of the OPEC policy, the Saudi policy. When Saudi Arabia cuts its production, they cut every fuel, every oil, you know. So we have lighter, we have a crude basket which is lighter, which is not very good when you need to produce fuel oil, and in particular, during summertime, when they use fuel to climatize themselves. So you have that. You have also the fact that clearly, the fact that today diesel from Russia or gasoline were sold to we have disorganized the global oil product markets. Everything was organized to shorten the cost of transportation. Today, it's more expensive. So all that has an impact we see today. Will it last? And that's true as well, but, so it's linked to the OPEC policy, but it should normally, when prices are going up, refining margin are going down, you know, there is a sort of... It's not the case, so Bernard is super happy. Not sure to fully understand why. To be honest, internally, by the way, the margin until June were quite average, even quite low. Suddenly, we see them going up in summer. Nobody told me, end of July, but they will go up in August, so I'm a little... I'm cautious about it. So I'm not sure, I'm not sure it's a fundamental reason, as it's more complex refining margin. Okay, let's take it as long as it's good, and, then... So why $35 per ton is just the assumption which we, we take on the long term? Because don't forget as well that our refining system and proxy in Europe have been hit by the 2, 2 impacts. Cost of energy. Natural gas is more expensive in Europe, so it's more expensive for our refining system. We shifted to LPGs. We shifted, but it's more expensive. And cost of CO2, I can tell you, because these the new policy of European Union on lower, less free quota has an impact on the break even, on the margin of refining the refineries. That's also why we think that it's time to transition some of these units, because cost of energy will not go down, and cost of CO2 will not go down. So all that has an impact. Even if you take action, like we try to do or want to do on hydrogen to decarbonize part of the cost, which is part of the economic equation, by the way, you don't solve that fundamentally. So 35 might be, might seems low to you. To be honest, when I was in charge of that, it was lower from time to time, and sometimes we have some debate with Bernard about is it too high, 35 or not? So today, at this point of time, yeah, we are at 100, but it's very super volatile, and we were at 150 a few weeks ago. We are down to 100, which is high. So I, I don't see... Except the fact that inventories are low, which is true. That's something which is clear in the market. Inventories are low, which support, I think, these margins. Except that, and again, this idea that the crude basket has moved to lighter crude, which has an impact on the refining—on some refining of some products. There was also this year the fact that a good, strong demand back on jet fuel, but that is down. We don't expect growth of jet fuel demand next year at the same pace as this year, because it was a recovery from the COVID. It's down, so that should also count down these margins. Wonderful. Thank you. Who else in the room? We have somebody there. Henry? Sorry, Henry, I don't see you. Henry. Yes, thank you. Henry Sherwood from UBS. Thank you for the, the presentation. Just one question on the low carbon molecules. You mentioned that you'd seen a good progress in SAF. You also mentioned your efforts in hydrogen. So I wanted to ask you about some of the other areas here in in biogas and also CCS. Looking back over the past year, whether the projects progressed, regulatory developments, whether anything has changed that would rechange your outlook at 2030 for these businesses? No, we, we did not cover voluntarily everything, because first we need to... We want, there is a message within presentation is that, our key focus is integrated power, and, we cannot, become a sort of energy conglomerate looking to everything. So we take some action, some packs. CCS is interesting. We decided that we focus on the north, on European, because we have a position, legacy position in North Sea, in Norway, in, in the Netherlands, in Denmark, in potential UK, where we can-- we have better understanding of system. We have also some assets that we want to reconfigure. So that's of a key focus for, I would say, developing a business of CCS as a service beyond CCS for ourselves. So we can, we will develop capture for on our own assets, like we do in Australia, in Ichthys, or what we want to do in Cameron with our partners in the US, but it's more driven by the asset. CCS as a service, by the way, Europe wide, but there is something which honestly, we have some doubts. I have two doubts on CCS as a service is, will the governments allow us to make that as a real business or a regulated business? Because it could be considered as something which you need to have, give access, and I would not be surprised. But if you ask subsidies to develop CCS somewhere, I will tell you, "Okay, my dear, maybe you should control the profitability of it." You have a second issue, which is a long-term a long-term. Liability ... liability, on which- I would like to be sure that we don't overexpose our companies on the long terms in some jurisdictions. So these are the two limits for me as CCS, as a service beyond it. But again, on Europe, we are active. We have several projects. Remember that we are part of the only project which really works today, which is Northern Lights, and we are supportive of expanding Northern Lights to phase two. And so- and we work on Aramis in Netherlands and other projects in Denmark. So that's for CCS. On biogas, we have established a position in France, which has a strong agricultural potential. It's interesting, but it's a niche business for me. It's not-- scaling up biogas production is quite costly. We cannot do everything. It's an interesting market because there is more demand for biogas than of supply, so the price is good. But in terms of volume of what you can do, it's quite a headache. So we'll spend some money concentrating on France. We have taken a position in Poland, I think some position in the U.S. It's not at the same level of priority that our integrated power business. Any other question here? Yeah. Please, Alessandro. Thank you. Alessandro Pozzi, UniCredit. Just wanted to go back to the LNG. As you pointed out earlier, there's a lot more projects under construction and not just in LNG, but across the onshore LNG, we're seeing more project being FIDed. And I was wondering, can you maybe elaborate on the type of, say, cost inflation, if any, that you see in LNG project, but also across the upstream industry? And especially, especially for LNG, whether labor shortage could be a critical factor, manpower experience, manpower and engineers to design and develop those projects. The second question is on biofuels. What would it take to increase the 1.5 million ton per year target in 2030? Do you want to see more demand or you want to have more control on the feedstock? And how much of that 1.5 is, in terms of feedstock, comes from your own production versus how much you need to buy in, in the market? Okay. It's a good question on LNG. In particular, in the US, where we see quite a cost inflation. We have selected at the end, we looked at several projects last year to increase our position. In the US, we have selected this Rio Grande LNG project because of its location, in particular. It's not in Louisiana, it's in South Texas, where you have quite a lot of workforce, according to Bechtel, which is our EPC. And in fact, it was last year, we studied several projects where we see quite a lot of cost increase in CapEx in terms of dollars per ton. We renounced to some of them because of that, and we selected the one which was offering from this perspective for us, the more interesting case. And we have a debate today on the carbon energy extension, because exactly that, because today, the cost which has been proposed, the EPC costs are much too high and we prefer probably to... If we don't manage to find a way to go down to something reasonable, we prefer to keep the option for the future by rushing. So in the US, there is clearly a case. That's why when people say all these pre-FID projects, I'm not sure that all of them will come, to be honest. And it's clear that you are very clear in Louisiana. I mean, in this big part, you have a shortage of workers, in fact. And so you have to be careful in capacity to execute, which might also delay the project. So that's why I made a comment about the schematic which was presented by Helle. On biofuels, no, we don't produce our biofuel. To be honest, I'm not, we have a capacity. No, we don't produce ourselves. We buy or we integrate, which was the idea, and this is clear. That's the point. Should we look to intercrop production? Yeah, I mean, we, there is a point where we need to better understand. But no, it's clear that it's a limitation, but 1.5 million tons per year, at the horizon of 2030, I think we're in a market which will be around 20 or 25 million tons. It's quite a good position. It's more we want to grow it. It's linked to our assets. We will not make greenfield assets, to be clear, the greenfield development. We transition our asset or we build on our Korean assets with Anhua, on which we want to look seriously to do something Korea. But so it's linked to our assets and the way we look as well to develop some soft production in Saudi Arabia around SATORP, which is with Aramco. So it's more, it's a mix of driven by the asset and then transitioning the asset, and then finding the feedstock, controlling the feedstock. We've done a JV in Europe to control the feedstock, which is key in terms of volume and in term of cost as well. So I think this is an integration model we could develop in the future. Okay. On, on LNG, just to clarify, when we see the Mozambique in the cost curve, that is based on the old cost estimate, I guess. With the new cost estimates, where would we- No, it's based on the cost estimate we have today. That we have? Okay. Including the cost of, because we have some suspension costs, which were around $1.5 billion or more or less? Right. $1.5 billion, which we had to pay in order to suspend the project during Okay ... this interim period. So it's, Because it's below on Papua LNG, so potentially- But it's much larger as well. It's benefiting for much larger. The base of, it's much larger project. Scale in LNG is quite important. Papua is an interesting one, but it's why we try to develop maximum synergies Exxon plant, on PNG, because, but, you have, seven ATCF. You make a project of 6 million ton, not a project of 15 million tons. So, you know, it's not a-- the scale in LNG is fundamental- Mm-hmm. On cap cost. But so Papua is a nice project. That's why we actually made that scheme, where we develop the F3, but we synergize the whole plant with a PNG plant, in order to lower the cost. So you're happy with the costs that we're from Mozambique, where they are now, or you want to push them down? No, no, we will are be happy with the target we put in this figure. Okay. So we need to work still. All right. Thank you. But we are not far to... I hope so, to be happy. Any other question? We have questions online still, so maybe we can take the one from, Peter. Peter? Peter, yeah, Peter. Peter, go ahead. Peter, and- Hi. Thank you. Yeah, it's Peter Low from Redburn Atlantic. On the $1 billion of cash flow growth from downstream low carbon molecules, can you perhaps outline the key projects and building blocks behind that? And is it fair to say it's predominantly coming from petchems? Then also perhaps the phasing of that growth, in the 2023-2028 period. Thanks. It's not only the low carbon, it's downstream and low carbon. So downstream is in particular with Amiral project with Aramco and SATORP. But it's also, by the way, marketing. Don't forget the marketing business from Thierry. He's also continuing to develop his cash flow. It's not because we divest an asset, but we don't have other sources of growth. And then you have these projects on sustainable aviation fuels, which will deliver some cash. So it's a mix of these three pillars, which gives the additional $1 billion. We have Ahmed online- Yes ... from Oddo. Ahmed? Yeah. Hi, Ahmed Bensalem from Oddo BHF. Thank you for taking my question. Patrick, I have just one on Namibia and the ongoing exploration campaign. We were expecting some results in September. So is it as positive as expected? And if possible, could you give us some indication on the results of the test and the size of the reserves at this stage? Thank you. Ahmed, you should listen to my speech because I answered to your question. So I said, I explained that we made a test which is positive, which is as per expectation on Venus-1X, which was the appraisal well. There is an upcoming test on Venus-1A, which was, which is, was a discovery- Mm-hmm ... well, or I don't know. We have two tests. And then we are continuing to explore on the north, a prospect called Mangetti, and we'll make a last appraisal well on northern part of Venus. All that being positive and will lead to a first development, but we need to continue to make all these projects. I also mentioned that there was a dry well on the... which has been drilled- West ... on the eastern, western part, which is called Nara, which is discarding part of the, the second block we had on the western side. So it's positive in terms of, but it's - I also mentioned that don't believe that 10 billion, it's more in billions than in 10 billion. Okay. Okay. Any other? I think that we cover everything here. Okay. It was quite a long Q&A session, but we are, like, perfectly on time. 1 hour, 12, 12. So exactly, so very well organized. Shorter presentation and more questions, which is a good recipe, I think. So I hope we, that we have answered your question. So we'll have now, we'll share some time with you. Yes. We have a lunch where we'll continue the discussion with all the executive committees. Some of you will meet my colleagues, and some, Henry, Jean-Pierre, and myself will have a traditional one-to-one road shows. But Nicolas, Stéphane, Bernard, Namita, and Thierry will be this afternoon at your disposal for the ones who have asked to meet them. So thank you again for your attendance and today. Thank you.