TotalEnergies SE (TTE) Earnings Call Transcript & Summary

Good morning, everyone. We are delighted to welcome you to TotalEnergies Strategy and Outlook Meeting 2024. This is, of course, a special event this year as we are still celebrating the 100 years of TotalEnergies. So today, of course, we'll be talking about the strategic outlook for the company, but we can also take this opportunity to reflect on the long and successful history of the company, which are making that we are here today in New York City with a nice view on Central Park. You can follow us live on our website, totalenergies.com. The program today will start with the strategy and outlook presentation, which should last around 1 hour 15, 1 hour 30 mins, and then we'll be moving to a Q&A session, where you will be able to ask all the questions you want. We have a dedicated line, which is open for the people who could not attend the event and will take from time to time some questions online. We should be done around 12 p.m., and we will then go for the lunch. But to start the meeting, and as it is a ritual at TotalEnergies, I invite on stage Vincent Stoquart, who is our new President Refining & Chemicals for a sequence on safety. Vincent?

Thank you, Renaud. Good morning, everyone. Happy to be with you today and to share this safety moment. So if you go to the appropriate slide. So you probably know that TotalEnergies celebrates its 100th anniversary this year. So this comes with 100 years of experience to improve continuously safety, which is our core value. And one key element of that is what we call the return on experience process and what we call the REX. REX has proved efficiency in order to share through the whole company, this experience and to avoid accidents. So I just wanted to mention that because today, we push that forward, thanks to our digital factory and to artificial intelligence and to take a very concrete example. In our industrial facilities, we need to have work permitting in order to start our work. And we have deployed already today an application, which helps the operational teams to instruct this working permit thanks to data processing of all this material -- massive material of return of experience and then to suggest the appropriate safety measures, thanks to artificial intelligence. So it's a concrete real example, of what we do in safety with these new tools. I wanted also to come back on this continuous improvement with a few data. So the chart on the left, it's the usual total recordable injuries divided by 1 million manhours. What you can see there is that over the last 10 years, we have divided by 2 this important KPI and today, I think we can say that we are in the best-in-class peer group. And the same for the so-called LOPC. So LOPC, it's the quantity of events of loss of contentment in the process. And there you can see the same trend, so minus 70% of these kind of events over the last decade. And we have, of course, action plans in order to pursue that and to diminish even further. So thank you, and I will let the floor to Patrick Pouyanne.

Good morning, everybody. Great to see you today in New York or live on Internet. First, before I enter into the discussion just to -- you just have the chance to be introduced to Vincent by himself. So Vincent is our new President for Refining & Chemicals. Vincent and the people around the table -- this table is only with men so, It's not too much diverse. But Helle will be live today to speak about Asia from Tokyo. So you will have Helle speaking. And I -- you have Namita our OneTech President in the room as well as by the Aurelien Hamelle, new President Strategy and Sustainability. You know his face. So Bernard is President for Downstream and Marketing & Services. Nicolas, President, E&P; Jean-Pierre Sbraire our CFO; and Stephane, President Gas, Renewables and Power. And they will have the opportunity to share this presentation with myself. So just to set the scene, I would say today, what do we want to -- if I try to summarize what we intend to present you, we have a strategic consistency within total energy, so don't expect any change today from this perspective. The transition strategy has been established a few years ago. We are progressing on it, year after year. It's a balanced strategy between the two pillars, I will come back on it. I like what you are here today, and I will borrow to one of you the -- title. I read a nice paper called the Derisking Show. So we'll have a De-risking Show today. De-risking, I would say, on the growth part because it's important, we have a growth profile of energy and I will come back on it, including in oil and gas. We will be able to not only de-risk but to high grade and to extend it. And also derisking in terms of resilience of our business model, you know all of breakeven, you know about our low-cost operatorship. We'll speak about LNG and our portfolio, can we de-risk the LNG portfolio and, of course, for the benefit of all our investors. So we call this presentation more energy, less emissions, growing free cash flow. The free cash flow, in January we spoke about cash flow, but at the end, what is of interest for you is the free cash flow, which would fit your higher returns in the future. So I would say this is globally speaking, what the message today -- be speaking about sort of strategic consistency, speaking about the growth we have embedded into our portfolio and speaking about the resilience, as well and my colleague will come back on each of this pillar. So just before to engage in the strategy, the energy markets. Energy markets, this presentation is not -- it's coming at, I would say, a volatile time, to say the least. But first, before there are some fundamentals that I just want to remind you about the I would say, the demand for energy. It's not in this transition, I would say, energy transition. That's not the best -- is just part of the equation to guess. But what we are convinced and which explain why we have this strategy with 2 pillars is that we need both oil and gas in order to meet the demand and low carbon. On this chart, we have an assumption, which is to whether energy demand continued to grow around 1.5% per year. The population rose by 0.8%, 0.9%, and you have as well in emerging countries, population, which are reaching better living standards. And despite some energy efficiency gains, you have a continuous growth on energy demand as the fundamental. On this chart, we took a broad assumption that the objective of the COP28 of multiplying renewables by 3 could be met, which is not so obvious to be honest. But what happens if it was met. Of course, the renewable part will grow quite dramatically in meeting the demand. But we wanted to illustrate, but because that's a 4% decline on the natural decline on the oil production on the oil. And despite all the efforts to manage this decline by many operators. At the end, if we don't launch new greenfield projects, there will be supply gap. We put minimum supply gap because if the objective of COP28 multiplied by 3 is not reached, the supply gap could be larger. So we need to continue to invest in all. Of course, the gas, we put an assumption which is most of the gas demand is driving by the LNG capacity growth, and we will come back on it. And one elephant in the room being the coal because in this chart, there's a little decrease of the coal by 10%, [indiscernible], as Michel in his [ carbonomics ] studies are explaining to the [ planet ], but people should read what Michel has written. If we want to be a 1.5 degree, we should get rid of coal by the end of this decade. We are far from that. In fact, so even there, the assumption is a little optimistic. But I think it really COP28 renewable objectives multiply 3 folds, then there will be some impact on it. So that's the landscape, and that explains our strategy, which is to bet on 2 pillars: the oil and gas, the energy of today and some low-carbon energies, in particular, electricity and some bio-energy as well. Because this is part of -- what we need to develop to decarbonize this in this energy world. On the oil side, I would say, the more we look at it, the more we see year after year after, of course, with COVID impact where maybe people were suddenly thinking that this was the beginning of the decline of all. The reality is that the oil demand is growing. It's growing a little less than, let's say, 1 million-barrel of oil per day. We don't see, for the time being, the real impact of the penetration of low-carbon technologies. We see more impact today in '24, I would say, of the Chinese lowering economy rather than about the technology's impact. It's more a macroeconomic impact. So our view is that this decade, we could see continuous liquid demand growing for until 2030, a pace which could diminish because, again, low carbon technologies would engage. And with the risk, in fact, about the supply -- so what about the supply in today, it's at the core of all the debate, I think, in many places. Okay. We observe a non-OPEC supply growth, it's true. But again, ex-shale, U.S. shale, this supply growth is not very sustainable. So you have some few countries, but it's -- in fact, it will be more stable or even decline the ex shale -- U.S. shale is a source of growth, for sure. You have the OPEC policy, which is today, again, put into question. I think I interpret the Saudi message to their friends of OPEC and OPEC+ that they need to be compliant with the quota. Otherwise, they could act as they've done in the past. So we'll see what happened. And all that being -- the supply being in a global framework for constrained investment because, in fact, we come to invest today less in oil -- in CapEx in oil worldwide, but what we are doing in the year 2010, 2015, you should not forget that. And so that's, of course, this global framework of constrained investment if the demand continue to go even beyond 2030, that will impact the price. And so on our side, I would say, and I understand that maybe today immediately on short term, it could be surprising, but we are more thinking that -- we are more bullish on the oil price, which explains why we continue to maintain our portfolio. The second market, which, of course, is very important for us is the LNG. It is clear that we will face a supply wave of LNG by '27, 2030. We made the math. I was making the math. It's in -- '27, '28, '29, you have plus 50 million tonnes of new capacity per year, which makes more or less 10% of the market additional capacity. So it's 30%, in fact, when you take a few years, which is not the first time that we face such a situation. In 2010, 2011, we faced already a situation where suddenly we impacted the market by an additional 30% of new capacities. And in 2016, 2018, there was also a wave of new capacity. By the way, it's an industry, the LNG, which is completed by wave because it's massive CapEx. And in fact, people are older -- ships -- mutants, we follow the others. When the price is good, we invest and then certainly, you have the wave. So the good news is with wave is that in between there is no new capacity. So in between, you capture, I would say, because the demand continues to be there for gas. So you -- it's a good market like it is today. People complain about gas price, but I'm happy when I see $12 per million Btu and the European gas price, I mean, it's not the $20 or the $30, which was completely exceptional, but we cannot complain about $12 or even $13 with more than $1 per million BTU in Europe compared to what we could have experienced, $5, $6 -- 5 years ago. So we should never forget that. And then so you have periods where capacity like '24, '25. I know there is a debate on '26, but honestly, when you see the announcement of our colleagues, I see more delays than really acceleration on any of these LNG plans. And so we think that '26 will remain -- it's only 25 million tonnes, which are expected of new capacity if they are on time. So it's '27, '28, '29. The lesson as well of the past is that each time you have a new capacity, a new wave of new capacity of LNG. Of course, the price are softening, and it's a market which is quite sensitive to the price. And so it fosters the demand. It was exactly happened in 2010, '11. It's again, what happened after the wave of '16, '18. So I think -- by the way, it will be good for this market because what with the prices we experienced in '22, '23, we see some customers begin to be afraid by this hike of gas is usual. So we will enter into that market, and we have to face it. And we will explain you -- our total is preparing itself TotalEnergies, sorry, if we are preparing ourselves to these capacity wave as we are part of it. So we cannot complain about it. It's part of the strategy and the way we, in fact, want to manage it. Just the last word, when we said that we anticipate an average growing demand of 5%, 6%, when you take the history of this market, it was 5% for decades. Plus the demand is quite largely led by the supply. It's a question of catching up and then to the next wave. So last market interest for us is of power, the power demand. So we don't speak today about hydrogen, but about AI, data centers, cryptocurrencies, People are -- I just want to remind everybody that yes, it's a growing market, but it's only 2% of the electricity demand in today. These data centers -- not big. So even if you double it of your triple it, you go to 2% to 6%. So yes, it is a market. It's a market, in particular, in some key countries. And for us, it's coming when you look data centers in the U.S. where you need to have, I would say, base load clean power for this tech company, this is what they are asking us. It's an interesting market, and Stephane will come back on it. But to say I can read that suddenly, it could be too much demand for that. I think we can find a way to -- it will be included in the global power demand growth, which is an average 2.5% per year. This year, it's 4%. Next year will be 4% again. There are some few key countries there again, and we will see China as a huge growth and India as well are the 2 countries we are leading the global demand for energy or electricity. The good news with the data centers, AIs, cryptocurrencies but there is also a growing demand in a country like the U.S. which is a good market for developing our business. So move on after the landscape and the energy market. I'll move on the way we execute our transition strategy. So there are two pillars. You know it. The Oil & Gas Integrated Power. They are not exactly on the same size. It's by 2030, it should be 80% on one side and nearly 20% for the Integrated Power. On oil and gas, we have the benefit of the depth of our portfolio. We'll come back on it. And so we -- today, we will firm up. We are high grading our guidance for our Oil and Gas growth to 3% from 2% to 3% to around 3%, not by -- only by 2030, we extend it, but you will see that even from 2025. We have also a large deep LNG portfolio, and we will explain you why we think it's resilient for the size goals. And at the end, all this business, and that's part of the presentation, which is an additional cash flow -- or free cash flow, more than $7 billion of free cash flow will be generated on the -- between today and 2030. Integrated Power will come back today on the model. More and more, we speak about integrated model, clean firm power for customers requires a combination of gas, batteries, renewables. And Stephane will explain you why we think that we should reach at least 12%. And we will reach only 20% of return on capital employed, and being positive free cash flow by 2028. This I would insist because I've always a question about why do you think this combination could be good for our shareholders. But today, we benefit from being the -- having offering in [indiscernible] the highest return on coverage capital employed. That's the calculation on the 12 months by end of June '24, it was the same the last 2 years. And we will offer for the future the highest energy production growth, energy covering all type of energies, not only oil and gas but also electricity and Bio-energy. So coming on Oil and Gas because growth. But true that we -- since last year in September, we worked hard within TotalEnergies to derisk the profile that we have proposed you -- of our growth, not only with derisk, but we high graded it, and we also today can extend it to 2030. So the guidance we gave is an increase of 3% per year as an average. We benefit -- we have worked hard to sanction many projects in '24, which will fit this bit growth. Kaminho in Angola, Sepia 2 and Atapu 2 in Brazil. And yesterday, I was myself with Nicolas in Suriname for the sanction of the new GranMorgu, 220,000 oil per day oil projects in Suriname. And we also sanctioned some LNG projects. Marsa LNG, which was not in our profile last year, it's not a big project, but as we have 80% of it, 1 million tonnes, 1.2 million tonnes. It's interesting project in Oman. And we also have worked in order to increase our gas supply to the future LNG '27 Nigeria LNG plant, which suffers today over lack of gas. So it's an opportunity for us to accelerate the production of our gas reserves in Nigeria. But on this slide, I want also to insist on the fact that the growth does not wait for 2028 or 2030. It's starting from next year because we have started in '24 and we'll start in '25. A number of new projects. We started Anchor, we started Fenix this year, Mero 2. Mero 3 will come on stream before year-end. We will have Mero 4, the first phase of Ratawi in '26, we'll have Tilenga and also from Qatar. So the growth profile is not only something which will come at the end of the decade. It's starting from '25, and it will be related in '25 and '26. And this will help us in case of low -- I would say, lower prices to have higher revenues, so to face volatile price if it happens next year. To do that, I want to introduce to you today to give visibility because we have many questions about of how much do you spend to do all this growth. So we give visibility on the organic CapEx and then I will come on the net CapEx. The organic CapEx, when we look at that, it's around $18 billion, $17 billion, $18 billion for the next 3 years. And you will see that we keep the guidance of $16 billion to $18 billion because at the end, the M&A will divest an average of $1 billion to $2 billion. As we do every year after a year, so there is nothing exceptional, but I think it's important. And you can read it like -- in fact, fundamentally, because we have a deep portfolio, we don't need to make large M&A. We have been very effective. We acquired position in Malaysia. We are continuing. You've seen that we announced last week, a second acquisition in the U.S. shale gas. It's part of the de-risking of our U.S. LNG position. but we'll continue to pursue some disposal of noncore assets. But on organic cash flow, there is the first 3 years are full, but there is room if we want to have our explorers continue to be successful, to FID new projects between today and the end of the decade. Keep in mind that now that we have derisked most of the projects. The EPC contracts are secured. So that mitigate project infection risk. And secondly, we keep, and I will come back on it, the flexibility to respond to changing market conditions. So organic CapEx. The framework for the global capital investment strategy is still the same. It's $16 billion, $18 billion, '25, 2030 around $5 billion for low-carbon energies, for Integrated Power a little less on for low carbon molecules fundamentally bioenergies and CO2/CCS and 1/3 on new projects. We gave -- we confirm the guidance that full-size calls, which will be $14 billion to $18 billion. And in fact, we kept -- we have in our portfolio, $2 billion of short-term CapEx facility that we can activate in case of brutal or sharp decrease of oil price. Sharp being lower than $50 per barrel in my mind. So we -- we are comfortable and why we are comfortable is because the balance sheet is strong. So in 2020, we maintained the dividend during the COVID. We can maintain our CapEx program and our return to shareholders because we have a stronger balance sheet, and we can use it if it's needed. A word about the LNG. LNG should be in the title there. But our energy portfolio, first, I just wanted because it's the same question that some of investors have. You have taken a strong position on I just want to remind you that first, we are investing in projects which have a low liquefaction cost top tier in the America. So the first answer. Second, in fact, what we do with Stephane team. And Stephane will come back on it, so I will not comment it in details. And you can see that we have worked quite hard the teams have worked out this year. in order to sign some medium, long-term contracts. And in fact, mostly index in oil, we transformed some Henry Hub into oil, which is not a bad deal. In fact, if you think about it, and we try to lower the exposure to -- and we want to lower the exposure to the spot price for the reasons I've exposed before. So we are working on it. More than 4 million tonnes of medium, long-term contracts will be signed this year. And we have also, by the way, one way to manage this Henry Hub is also upstream gas integration, the position we are building in the Eagle Ford, the step after first and the one we have in the [indiscernible]. Just a framework for integrated power. The more we move in that business, the more we see a huge value of the integration of gas to power, which for an oil and gas company is somewhere quite, I would say, natural. But sure that we have to invest in renewable assets, but if this renewable assets are intermittent and the value of an intermittent electron, in fact, for our customer is not very high. But if you manage and Stephane will come back on it to sell, what we call the clean firm power. And it's possible, thanks to the integration with the gas and the fact that we control also where we are integrated on the upstream gas production is giving us an advantage in terms of fluctuation of the gas price and the impact on the electricity gas-fired plant electricity price. So that's something -- that are the same. If we want to benefit for renewable developing some storage capacity, some battery capacity is also important. So that's this combination of renewable and flexible assets, which is a core strategy and which allow us to take some merchant exposure to capture some upside and also to have to enhance the value we get from customers. So we confirm on this -- the two key -- two key metrics, which are the target to produce more than 100 terawatt power generation by 2030, which is more than 500,000 barrels per day equivalent. And the return on capital, at least at 12% on this business -- being today attend and Stephane will come back on it. So if I try to summarize what we present, we will present you and my colleagues will give you some details. Our global energy production is growing by 4% per year. A little more. In fact, let's keep 4% per year. At the end of the decade, the electricity will nearly be 20%, 20%, more 18%, but it depends on different factors. So nearly 20%. We continue, of course, to be committed to lower our emissions. We are under way year after year, and all the business plans confirm that the minus 40% Net Scope1 and 2 decrease will be met by 2030. And also, it's important because it's, for me, is a key marker of our transition strategy. When we look to the average carbon content of our energy sales we are diminishing year-after-year. This average carbon content, minus 25%. And we are clearly leaders on this slide. I would say if the ESG funds are looking for transition funds are going more for transition fund. The business case of TotalEnergies is probably quite interested to be promoted. All that resulting in quite growing free cash flows. It's more than $10 billion at $80 per barrel, but even compared to today at $60 per barrel, it would be $5 billion. So -- and this free cash flow coming from both pillars, Oil and Gas, Oil and LNG is more than $7 billion and integrated power flipping from minus 2% to plus 1% will provide an additional $3 billion free cash flow. So before I leave the floor, a last comment, which is important because one of the -- for me, best success today of our transition strategy is a commitment of our people, which makes me very -- not only proud, but very confident that we will execute it. Just we make a survey every 2 years and we compare it to benchmarks to Oil and Gas benchmark, to be proud to work for my company, 90% of our staff is proud compared to a benchmark of 72%, and it was 88%, so it's even increasing. Maybe because I distributed them 100 shares to each of the employee on the 100 year anniversary, but it may be an effect I think so, but it's very high and it's, I think, a big asset. Confidence in TotalEnergies ability to achieve its transition 92%, continuing to improve to our people are more convinced that we are on the right track. Working in safe conditions, was just to support Vincent speech. They are quite as a feeling that they are in a company will take care of them. And this commitment to the strategy of the company, translate in fact, into shareholding. We do annual sharing capital increase for employees. And this year, they have invested $500 million, which is a record. So they today own almost 8% of the company. And so I think it is also important to understand the way we why the execution of the strategy is making progress year after year because we have some very committed employees all around the planet. So having said that, I gave you the lines of the presentation and now Nicolas, then Stephane, then Bernard and Stephane again will explain you -- present to you some details, the content of it. Nicolas, the floor is yours.

Thank you, Patrick. Good morning, everyone. So let me focus on Upstream, and particularly, I will start with a key strength of our upstream business is a sustainable, low-cost, low-emission portfolio. First, sustainable portfolio because as you see in the chart on the left, we managed to keep our reserve life stable over the past few years at 12 years of proved reserves, 18 years of proved and probable reserves. And we've been doing this because we kept our focus on oil and gas. We kept exploring. We kept developing the discoveries. We kept sanctioning new projects. So this is important because it gives our Upstream business a good longevity. While maintaining the reserve life, of course, we're working on decreasing our production costs and decreasing our emissions. In production costs, we've been, I would say, leading the pack of our peers in terms of dollar per barrel of production cost. This year, we had a target of an AC production cost below $5 per barrel equivalent, and we're going to deliver this target. We are on good track for the beginning of the year. This is a result of one; high grading the portfolio, but two; also the work of all our affiliates and teams to decrease the production cost, and I will come back to that later in the presentation. Same effort on decreasing the emissions. You see here the emission intensity, Scope 1 and 2 intensity of our portfolio. We expect to be a 16-kilogram of CO2 equivalent per barrel this year, versus 18% last year and versus above 20% 4 years ago. And you see in the chart that we expect our intensity to continue decreasing over the year to 2030. Of course, this is the result also of our investment criteria, which are not new. So you know them. They are recalled on the right part of the slide. On all our projects needs to have a technical cost. So OpEx plus CapEx below $20 per barrel equivalent or a breakeven below $30, on all our new projects need to have greenhouse gas emission intensity below the average of our portfolio. So in a key focus in Upstream today is the delivery of our projects, to deliver the production growth that Patrick was showing. And you see here on the slide, the top 11 oil projects of the company, which are going to start between 2024 and '28. So it's pretty busy. FID this year, Patrick mentioned it, we took FID on 4 large offshore oil projects. Kaminho in Angola and GranMorgu in Suriname on Atapu 2 and Sepia 2 in Brazil. Start-ups, 3 major start-ups this year. 2 of which have been achieved already. So we started Mero 2 on Anchor. Mero 3 is to come before the end of the year. And next year, we expect another 4 major start-ups in oil projects. Ballymore in the U.S., Mero 4 in Brazil, Ratawi Phase 1 in Iraq and Tilenga in Uganda. So what you see is that our portfolio of oil projects, is not -- I mean, it's kind of front loaded with a lot of startups coming in the next couple of years. These projects, they are well positioned in the cost merit curve. You see them here amongst the global oil and gas projects. So it's, of course, the result of our investment criteria. And finally, and probably more importantly, these projects are very accretive. You have in the subtitle, the cash flow from operation, the average cash flow from operations from the new oil projects $30 per barrel in a $50 per barrel low price environment on $50 per barrel of CFFO at $80 per barrel Brent. So to illustrate that, let me bring you for a minute to Suriname where we were yesterday to launch GranMorgu development project on Block 58. So GranMorgu, just for you is a big fish. It's a Goliath Grouper, about 2.5 meter long, so like our large FPSO in Suriname, and it's a fish by the way, that can live for 40 years, so which hopefully will be the duration of our production in Suriname. So the first point is this project is coming from successful exploration and appraisal by the company. Second, and Patrick mentioned it, I think it's important, we achieved a record 1 year before the end of appraisal last year on the FID of the project. It's a kind of pace that we want to see now for our new oil developments, 1 year between appraisal on FID. This requires a new way of working with our contractors particularly, we selected our contractors at the very beginning of the front-end engineering phase to be able to accelerate, in fact, the studies and accelerate the FID. So it's a large project. It's a material project. You have the figures in the middle of the slide, 750 million barrel, $10.5 billion of CapEx, 100%. It's a project that obviously meets our investment criteria in terms of technical cost below $20 per barrel in terms of greenhouse gas emission intensity, it will bring material production of 85,000 barrel per day upon startup from 2028 on a material CFFO, $1.3 billion at $50 per barrel. The project has a few new technological features to decrease the emissions. It's an all-electric FPSO, highly energy-efficient with a number of innovations to improve the energy efficiency. And it's going to be our first FPSO equipped with a full methane detection permanent methane detection and monitoring network with a network of sensors. Something that we are going to deploy by the way, in our other production sites. The good thing about the project also is that we have possible future tiebacks to extend the production plateau. So there is an upside to potentially further improve the economics. One point, I want to mention also or maybe I will comment it on one of the next slide is the way we've been working with the contractors on this project to optimize the cost. So now moving to the other side of the Atlantic. In Namibia, continuing Namibia media exploration. So first on Venus. You recall that on Venus after the discovery, we drilled 2 successful appraisal wells. So we are now progressing the studies on a development of 160,000 barrels per day. There is a material volume of oil. There's also quite a bit of gas that needs to be [ ejected ]. So today is the work of our teams and engineers is to optimize the well place on to optimize the FPSO to ensure that we have a project that is within our investment criteria, particularly with the cost below $20 per barrel. For one, we are planning, of course, to follow the same approach as in terms of working with our contractors early. Future exploration. Today, we have a drilling rig on its way to Namibia to drill a prospect called Tamboti which is north of the Venus, which was derisked by a well drilled last year, we called Mangetti. And beyond Tamboti, we have a number of prospects in the south of our blocks in Namibia, but also in the same basin north of South Africa, offshore, of course, on blocks on 2 blocks, [indiscernible]. So we are looking forward to drill this next year, with several actually large prospects that were confirmed by seismic. Let me now turn to what we are doing to reduce our cost, both in projects and in operations. And I will start with our CapEx and our project cost where starting with the first example of what we've been doing in Suriname to reduce the cost by using first an existing design for the FPSO. So the FPSO is standard. We've been using the contractor referential as a basis for design, similar actually to what one of our peers have been doing next door. We've been reviewing on how we do this systematically all the equipment bearing philosophy of the project to be able to decrease the number of equipment and at the end, reduce CapEx. Another example is Iraq, onshore. So onshore today, what we are really looking at is to decrease the footprint of our facilities in our gas growth integrated project in Iraq, we managed to reduce by 70% the footprint between the initial conceptual studies on the status today, which, in fact, brings a lot of saving in terms of site preparation, but also in terms of piping and everything. And we leverage also on regional contractors to keep our cost low. Like in Suriname, we worked a lot on reducing the equipment buying. You see an example here on gas turbines, to keep the cost at the lowest level without compromising, of course, safety and availability. We don't only challenge our, I would say, engineering practices, design practices. We also challenge the way we work with our contractors on 2 examples of that. One, you know certainly already, it's in terms of rig ownership where we decided to acquire 75% of a rig, to hedge rate cost against inflation. And also today, we work very proactively in all [ of our ] tender to enlarge our contractor base, and particularly to include more non-western contractors and more Asian contractors in particular. Turning to OpEx. So on OpEx, as I mentioned, we worked quite hard to reach an operating cost below $5 per barrel. So we intend to keep that to keep that, and to fight to keep that competitive advantage. Working on 3 axis. So the first axis is what we call the lean operating model. So lean operating model is about reviewing the organization of our operations on all sites, from production to inspection, to maintenance, to logistics in order to execute those activities in a more efficient manner to reduce our POB offshore to be able to prepare work onshore, execute onshore, to demands of our facilities to reduce the frequency of maintenance, et cetera. On doing that, actually, we get I would say, a lot of leverage using digital solutions. The second axis is to continue reducing our logistics and procurement cost, by rationalizing our logistic basis, by optimizing the way we use our transportation means by improving the way we do our offloading operations, to logistics and contracts. On the third axis is to work on structure cost and particularly on reducing the structural cost in mature affiliates, typically in some of our North Sea affiliates, Denmark U.K. or West African affiliates like Congo or Gabon. Overall, our target is to reduce our annual operating expenditures by $500 million per year over the next 3 years so '25, '27. So when we look at our OpEx base, it's about 3% OpEx reduction, 9% over 3 years, which will offset inflation, and in fact, that's our target is to offset inflation and keep our OpEx below $5 per BOE. So I will note give the floor to Stephane who's going to talk about LNG, which is also an area with numerous projects underway.

Thanks, Nicola. Good morning, everyone. So I will now present to you our integrated LNG strategy, and I will start by reminding you of our starting point. What we have today, and as you know, we are #3 in LNG with an integrated portfolio of around 10% market share. And that portfolio is mostly based on the long-term supply coming 2/3 or 60% from our own production and 40% from our third-party sales. Don't have a map. So -- and in terms of geography, we are mostly supplying from the U.S. from Middle East and to a lesser extent, from Africa, Asia, and as you know as well, Russia. This portfolio is going to grow. This long-term portfolio is going to grow by 50% between now and 2030 thanks to our project or pipeline of projects, I will present in the next slide. Now as Patrick has mentioned, we know that a big wave of LNG is coming, and there is clearly a risk that the market is oversupplied by '27, '28, '29, '30 with the softening of the price. And so the question is how our portfolio will react to that cycle. And we are convinced that with all the work we have done today, we have a resilient portfolio to go through that cycle and for fundamentally 3 reasons. One, our growth is based on project with low breakeven point price. Two, we have been able to fundamentally derisk our revenue to sell our LNG on Brent index and not on the gas index. And three, we have been able to do that while keeping our optionality in the portfolio and our capacity to arbitrage notably by bringing our U.S. volume in Europe or in Asia. So we'll start now by the production. And as you can see, we have -- our growth is based on the portfolio of projects, which are mostly under construction and we start up, which will come from early '26 to '28, '29, most of them being currently under construction. If you look at them, so you've got two projects in North America. Costa Azul in Mexico and Rio Grande in the U.S. Costa Azul as being a competitive project because of its location and saving because it's on the Pacific coast and Rio Grande being one of the most competitive projects in terms of liquefaction fee, it will be the best in our portfolio. Then you have 2 other projects in Middle East. One is Qatar. Qatar is well known as the cheapest gas in the planet, the most competitive LNG. And we have been able to join both Eastern and South expansion. And we've got as well the Marsa project, which is a small one, 1 million tonnes. But as mentioned by Patrick, we have 80%, and that's fully electric drive project fueled by the web by green electricity as well. So in terms of CO2 content, that will be probably one of the best in the world. Finally, you have Train 7, which is benefiting of the synergy with the first train in Nigeria, and Mozambique LNG that you know quite well. And then 2 other projects that have not yet been sanctioned, Papua LNG and Cameron Train 4 and the reason why they have not been sanctioned because we are not satisfied by the level of CapEx we have reached so far. And so we have gone through a process of re-tendering to see if we can improve CapEx and sanctions. Where does that leave us? That leaves us with ranges project, which are -- on the left part of the merit curve, so it's not ours. It's a Goldman Sachs one, and where we have mentioned where we are with very competitive project in Middle East a nice one in the U.S. in that curve, assuming that Henry Hub [indiscernible]. So that's for the production I move now to the sales and on the slide, what have we done in '24. What we have done in '24 is fundamentally to try to sell our LNG in Asia on a Brent index -- on the Brent index. And you see that we have already achieved 4 million tonnes of sales at the public quantity. You've got a few other coming very soon. And we have been able to do that increasing our market share in China, notably with [indiscernible] in Korea with a small player, but nice contract, Koen and Hyundai, and in Singapore and in India. And so those sales are mostly on index Brent with actually a nice slope. So where do that leave our portfolio? And you've got that on the left part of the slide. If I look at '24, the left column is on which index we are buying our LNG it could be spot price. It came TTF, hit could be Brent or it could be Henry Hub typically if it's sourced from the U.S. And on the right side, you have what we have committed to sell. We can sell on Henry Hub. Typically, we have some contracts in LatAm, where we are selling on a Henry Hub basis. That's one. we can sell on Brent index typically what we are doing in Asia. And then we have some contracts that are -- Des Europe, where when you are Des Europe by definition, you sell based on the TTF. That doesn't mean that you can't reload, but the destination of your cargo is Europe. So your index at the beginning is TTF. And you see that we could be in a situation where we have more supply than sales the difference is something where you can decide actually to sell it on the various markets. If you wait by you sell it in spot and if you don't wait, you can try to sell it, on typically a Brent index. What is interesting is that we see that our supply based on Henry Hub is going to increase a lot, not that much for the Brent and a bit for the JKM. And you can see that on the sales side, what we have done was to increase significantly the volume of LNG, we are selling through Brent index, both in '28 and 2030. Why have we done that? And that the right part of the chart is to look at the net difference between the sales and the super. And when you make that net you see that fundamentally, the exposure of our portfolio in '24 is to buy Henry Hub, around 5 million remaining position. And to sell that on the JKM/TTF index and went further on the Brent index, which means that we have been able to benefit from, as Patrick was mentioning, the $12 of TTF. With the evolution of the portfolio between the contracts we signed and which are all starting in '27, '28, you see that in '28 fundamentally, we will be buying Henry Hub selling on the Brent without any more gas exposure. And in 2040, it's not yet the case. But we are, as I said, working on it with that idea that we will, on one side, buy Henry Hub and only sell Brent. Two additional comments I would like to make is the fact that we have the view that the market will be with TTF softening price by 2030. It's not necessarily going to last forever. And our contracts are not lasting forever, which means that by 2032, 2033, you've got contracts that are 4, 5 years. you could find back your gas exposure, if you wish. That's one. And second, it's not because you sell long-term index brands in Asia that you lose the opportunity of arbitrage. We can still continue to divert cargo between Europe and Asia. So to conclude, where does that leave us in terms of quantity and cash. We have put a comparison between where we are this year, '24 versus '28 -- 2018, sorry. Why have we chosen that because that in terms of price, in terms of Brent and gas quite similar year and it's not polluted either by the [indiscernible] or by Ukraine war. So if I look at the past, what you can see that -- we have been able in the last 6 years to grow significantly our portfolio from 18 million to 30 million tonnes. And that growth was actually accretive because our cash was multiplied by the 2.2 during the same period, if you really restate by the price. So that's for the past and that the intrinsic improvement of our portfolio. And then when -- if I look forward, you see that we are pretty much going to increased by 50% our volume. At the same time, because we are relying on a really low-cost project. we plan to double our cash flow generation. That's one. And second, that's the way we do that. By limiting as well the sensitivity of our portfolio to gas because fundamentally, we will be mostly selling on the Brent index. And you see that the sense and you see the sense -- the resulting sensitivity of the cash to the Brent price. In summary, a resilient portfolio through the cycle, thanks to one; low-cost breakeven project; and second, derisking the sales by selling index Brent. And I will now hand over to Bernard.

Thank you, Stephane. Good morning, everyone. So let's move now to downstream. So as you know, over the past years, downstream has been a segment which has been a steady contributor to the free cash flow of the company. And this has been achieved while transitioning, executing a strategy made necessary to meet a triple challenge. One, of course, is to adapt in Europe to a lower market demand for oil products. Secondly, to reduce our CO2 emissions worldwide from our operations; and third, of course, to provide and develop for our customers, low carbon solutions. So how are we executing this transition strategy. First, we set ourselves a target. I'm sure you will remember, to align our sales to our production to get to a higher integration, a longer value chain and, of course, to enjoy a more balanced profile between upstream and downstream. And as you see on the left-hand side of the chart, in the past by 2019 -- '19, you see we used to produce -- we used to sell much more than what we refine and refine much more than what we produce. And since 2019, things have made -- have changed. We have made a lot of progress because we have reduced our refining capacity by 15%, and we have also reduced our product sales by more than 30% to concentrate on the most valuable part of the portfolio. And as of today, you see that we are well on track to meet this target to be balanced between upstream and downstream by 2030. All this transition strategy, of course, is executed in the framework of a very strict capital discipline. And if I start with refining chemicals, it means that we are allocating our CapEx to projects, which enjoy the lowest breakeven points to be resilient across cycle, and that's true notably for petrochemicals, where we invest in projects benefiting typically from cheap feedstocks, ethane, LPGs. A good example being our projects in Saudi Arabia, the project Amiral. That will be a world-class petrochemical platform, downstream from our set-top refinery that will start in 2027. And there, we enjoy from very cost advantage feedstocks in the Kingdom. That's true also for our sustainable aviation fuel projects where we leverage our existing assets, our existing refineries to develop low CapEx projects, but I will come back to this in a few minutes. For Marketing & Services, here again, we favor a strategy that we call value over volume. It means that, for example, in our retail network, we concentrate on the geographies where we enjoy leading positions, mainly France and Africa. And in our high end -- in our specialties, we focus on the high-end applications, notably in Lubricants. But once again, I'm going to come back on this in a few minutes. So all in all, we as a target to deliver by the end of a decade, an additional $1 billion of free cash flow in the Downstream segment. So what I would like to do now is to give you a little bit specifics by going through some key projects. I will start, of course, with cost savings, not a surprise in refining chemicals because cost savings is a sense to lower our given points in a cyclical industry. And if I start from the left, of course, energy costs is one of the main, if not the main cost centers in refining chemicals, and this is where we have to work to be cost competitive and also, of course, to reduce our CO2 emissions. In 2023, we launched worldwide, an energy saving plan. We even called it Energy Savings Acceleration Plan, of $1 billion to be executed over 2023, '25. And out of this $1 billion, $400 million were dedicated to refining and chemicals. I must say that it has been a tremendous success with a huge engagement from our employees, including on the field. We have been able to identify close to 250 projects such as, for example, recovering heat waste to be used in [ pre-heaters ] for steam crackers, electrifying with green electrons compressors to which we are operating with a steam before or, for example, reducing the fueling in heat exchangers. So there are many examples like that. And at the end of the day, all of this translated into $100 million a year savings as you see on the chart, and the 1 million tons of CO2 reduction. The good news is that by doing this exercise, we identified much more projects, many more projects with good payback. And therefore, we decided to launch a season 2 with exactly the same metrics, $400 million again to be deployed in '26, '28. We've already identified again, $100 million of cost savings in energy and 1 million tons of CO2 emission reduction. That's for the variable part, so it's very significant. But of course, we need to work on the fixed cost part as well, which is once again a key metrics when it comes to talk about competitiveness. And here, I would like to show how digital help us reduce costs. notably in the field of maintenance and inspections, which are here again, one of the main cost centers in a refinery. Let me give you just a couple of examples. If I take the innovative unmanned technologies that you see here on the chart. The example is very straightforward. We use drones and robots to inspect tanks. By doing this, we avoid putting in place scaffolding, which you know are first very costly to put in place. but which also bring a long period of unavailability of the assets. So by doing this, we save a lot. And last but not least, we also operate in a much safer manner. If I take the example of the IoT, a good example here also is the usage of IoT in the field of predictive maintenance. IoT allows the deployment of the predictive maintenance on rotating equipment, and that helps prevent early machine breakdowns of course, and reduce unplanned downtime. So all in all, I could give you many more example, but at the end of the day, all these projects translate on the fixed cost side by a savings of $200 million a year -- $200 million over the period from '24 to '27. And as you see, by doing this, we will be able to offset the inflation over the next 3 years. Let's move to Marketing & Services. As I said earlier, our strategy here is pretty simple. It's value over volume. What does that mean? It means, first, if we look at the retail networks, that we want to create value by concentrating the geographies where we enjoy leading positions. That's, of course, in Africa, where we are the leading petroleum products retailer on the continent, which is enjoying a growing demand. So I would say it's a winner. And in Europe, we're also refocusing strength, our presence in the country where we are a leader, mainly in France, namely in France, where we leverage our leading market position to grow our services in the field of nonfuel sales, food, cards, car wash. The second pillar is around the lubricants. Here, we will create value by developing a product offering on the high end of the market where we command higher margins. And we intend to grow also our range of sustainable lubricants. And this will be done notably through the acquisitions we have made a few months ago of a finish company called Tecoil, which is a producer of regenerated refined based oil and that gives us now the ability to provide to the market some circular lubricants. The third pillar is around electric vehicles, of course. Here, we want to create value by concentrating clearly on the development of fast charging points aimed at serving on-the-go customers, the one we are willing to pay more, commanding better margins. with hubs located in urban areas or HPC located in our service stations along the highways. And we also intend to develop what we call low equity business model through partnerships and leverage. A last example of how our transition is going to generate more cash is our development in the field of sustainable aviation fuel. Here, we are developing this strategy around 3 pillars. The very first one on the left-hand side, which is key, is around the feedstocks and the need to secure these feedstocks. As you know, in Europe, only given feedstocks such as waste and residues are eligible for the production of SAF. And this resource is limited. Therefore, it's critical to secure it, and we are doing it through integration of longer tech agreement with suppliers. A good example of recent move we have made is this partnership with SARIA. SARIA is a German company. It's a European leader in the collection of animal fat. And we have made with SARIA, 2 joint ventures, 1 Upstream where we have taken 50% of one other company transforming animal fat into bio-feedstocks. And SARIA, on the other side, has taken 50% of our projects in Grandpuits biorefinery to integrate themselves Downstream. And by doing this, with build winning combination and secured clearly, the upstream in terms of feedstocks. Of course, we also leverage our trading capabilities to enlarge the pool of accessible feedstocks. And we are doing it, of course, by making sure that we only source certified sustainable bio feedstocks. The second pillar, which is also interest is how we are going to produce SAF to be low cost because that's really of the essence. And here, we have made two clear choices. The first one is that we want to produce by doing coprocessing in our traditional fossil refinery. So what does that mean? It means that we directly inject the bio-feedstocks into the jet fuel processing units. We produce a blend which contains a certain percentage of SAF, and these blends can be directly incorporated into the airplanes. The beauty of this is, of course, that it only requires a few process modifications and very limited upfront CapEx. So it's a very, I would say, smart and low-cost way of doing stuff. And by 2025, we will produce by coprocessing 160,000 tonnes of SAF in our Normandy refinery, and we are about to start in a few weeks from now. The second choice we have made when it comes to producing Pure SAF this time is, of course, to retrofit existing refineries into bio-refineries. And by going this way, retrofitting instead of going to greenfield projects, we enjoy much lower CapEx. The CapEx intensity of retrofit is 40% lower than the one of a greenfield project. And this is why also we may benefit enjoy very low cost and low CapEx-intensive projects. And that's what we are doing in Grandpuits, project close to Paris, where we are about to start up because next year in 2025 we will start producing 200,000 tonnes of SAF, and that will be even 300,000 tonnes by 2027. So we are going, I would say, both ways. The third pillar on this growth strategy around the SAF is, of course, to leverage our market positions with our customers. airlines, Air France, KLM, OEMs like Airbus, we cooperate with them to develop to design the next generation of staff, of course, and leveraging our logistic footprint and setup, we secure also with them long-term supply agreement. And this is, for example, what we have recently done with Air France KLM, as we announced last week, if you remember, that we will provide Air France KLM with 1.5 million tonnes of SAF over the next 10 years. So in conclusion, what I would like to say is that through these few examples, you see that the downstream segment has a clear transition road map, and is well on track to execute it to deliver this additional $1 billion of free cash flow by 2023. And now I leave the floor back to Stephane.

So I will move to Integrated Power and how to -- we are currently building a future cash engine by future cash engine, we mean [indiscernible] by 2030, as explained by Patrick. So to do that, the first objective is growth and is to reach above 100 terawatt hour of production by 2030. It's not growth for growth. It's just that growth means that, that business will be of size equivalent to 500,000 barrel and that we have bargaining power with the supply chain. That's one. Second, we wanted to be integrated with -- what we mean by integration? That means renewable assets on one side, flexible asset on the other side. And you see that the idea is roughly 1/3 of Solar, 1/3 of wind and 1/3 of CCGT. By definition, you can only deploy that model on the regulated market and that's why we want to focus on the U.S. and in U.S., Texas and PGM Europe. Brazil, which is as well an open market and India, which is currently opening. Just of the world will be mostly oil and gas where you have a synergy with the rest of the portfolio. And all in all, the deregulated market should be around 70% of our -- of this production. When I look at how we are going to achieve that on the renewable side. So today, we are end of June, 24 gigawatt should be at 45 by end of next year with what we have in construction, what we are currently sanctioning. And if I look between all our JV with Clearway [indiscernible] and AGEL, and my own operation with the pipe of roughly 90 megawatts of different type of projects and different maturity. And we assume that 50% of it will materialize. The rest, it's either that we will get the permit or we decide that it's not good enough, not profitable enough, and we prefer to sell them back. So 35% plus 45% that gives you roughly 80%. So 80% of that pipe is already identified. The idea is to complete that with selective M&A notably to work on the integration and notably to improve the level of win we have in our portfolio. And you see that we want to reach roughly 50% of capacity in solar -- 40% in wind and 10% in battery. And note, by the way, that offshore wind will remain only 10% of our portfolio. Now if I look at the flexible assets on the flexible side, what we want is really to work on the integration. And that integration between gas production on one side and flexible generation between flexible generation and renewable generation. And when I look at the downstream of the value chain is to work between production and trading and sales access to the wholesale market where we plan to sell 30% of our production on a merchant basis, and customers for the remaining 70%, and I will come back to that with Clean Firm Power. So as you know, we were already integrated in France where we have some CCGT. We were as well integrated in Spain. We have worked in '24 on that integration. And that's the reason why we have purchased this on CCGT in Texas and in U.K. we have purchased as well some battery business in Germany to work on that integration along the value chain, and that's something we are going to continue to do. You see that when it comes to Germany, it's clear that besides our position in offshore wind, we should try as well to develop onshore solar and wind production. And as Patrick mentioned previously, that we would be happy as well to have some CCGT on the portfolio. Where do we want to have that integrated portfolio. One, it's because it's good to size trading opportunity in the market resulting from the of the volatility of the market linked to the intermittency of electron. But two, because we can generate value by selling Clean Firm Power. So what does that mean? 5 years ago, customers were buying guarantee of origin, which means that you were buying electricity in Texas and to say that it was green, you were getting guarantee of regime in India. There is no absolutely no link between both. So people have started to move and by corporate PPA as produce, which means that they identify a solar farm, they buy the green electron from that solar farm. But the truth is that solar electron doesn't meet their needs because they need base load, they need something that it shaped to their consumption. And what we see more and more at least in Europe, is that customers get burned by buying corporate PPAs produce because they are unable at -- in an efficient way to transform those corporate PPAs produced into what they need, and that's where we come with an ability to tell them, okay, I'm going to sell you the electricity you need and that electricity is going to be green. And the way we do that is that we provide electricity on one side. And we provide the guarantee of origin of renewable production of an identified solar or wind farm. And if they want that to be in the same region when they are -- we could do it, and they want that to be additional, a new investment, we can do it. Obviously, by doing that, we are taking some risk because when there is no renewable production, they need to provide power by producing it, and that's where you need a CCGT, for example. And when you have [indiscernible], you have to we sell them, but that's exactly the type of risk we are used to manage. And the fact that a fully integrated along the value chain allow us to do it in a very efficient way. And so we have started to sign a contract on that and plan to do more where we think that we can extract premium from the development of Clean Firm Power. As mentioned so why we believe that the integration and Clean Firm Power will help us to reach our objectives. There are two other pillars, and we are working. I won't detail them today. One is industrial journey where we want to be the best in terms of OpEx and CapEx, and when we've made good progress in '24, notably in terms of supply. And as you know, we are targeting to be in CapEx and OpEx in the second -- at least targeting to be first quartile. And from our benchmarking, we know that we are already second quartile in the U.S., but they are still at least 10% cost cutting cost savings that we should be able to do. So that's for the first pillar. And the second pillar is to continue to work on the farm-down. And this year, normally at the end of the year, has been able to farm-down around 1.4 gigawatts of assets. Some have already been done like [indiscernible] and others are on their way. So with these three pillars, saving costs on OpEx and CapEx, better sales, merchant exposure and Clean Firm Power and portfolio optimization, we are confident that we will reach a target above 12% of return on capital, by 2030. Where does that leave us in terms of volume and cash? So you see that on one side, we are currently at around 40 terawatt hour of production we should be above 100 by 2030 with 70% renewable, 30% flexible. And in terms of cash, we should be able to maintain the level between $2.5 billion and $3 billion in the coming year. And then that cash flow should progress with volume with the idea to reach above $5 billion by 2003. All that being free cash flow positive by '28. And I leave now the floor to Helle from Asia. Helle, floor is yours.

Thank you, Stephane, and good morning, everyone. I hope you can hear me okay. I just wanted to share a few words with you on Asia and our growth in the region, where it has been based for 8 months now. Next chart, please. So Asia is the heart of the energy markets growth. Why do we say that? -- very simply because Asia fuels the world's economic growth. Asia fuels a world population growth and therefore, Asia fuels the growth in energy demand. As you can see, Asia's primary energy demand grew by 2.6% over the last decade, which was twice as fast as the global growth rate. Going forward, the challenge will be to enable emerging Asian countries to reconcile the high growth in energy demand, which is an absolute certainty with less emissions. We show here 2 scenarios from the IEA on Asia's energy demand in 2030, continuation of the existing trends, which is step and the EPS trajectory, which is well below 2 degrees an year ago. Whether you believe in one or the other of these two scenarios doesn't really matter. The net message is at Asia orders huge opportunities for a multi-energy company like ours, linked, of course, to the pickup of clean energy. Renewables to cover growing power demand and LNG to [ back out ] coal, and those are, as you know, our 2 growth pillars. Next chart, please. With that in mind, Asia is to be a major outlet for the next wave of LNG supplies coming on stream between 2027 and 2029. You see here the growth in Asia's LNG demand between 2015 and '21 was 8% per year. Then you see the dip in demand in 2022 in Asia had to compete for available LNG cargoes with Europe. And since then, renewed demand growth with a nice upward curve. Asia represents roughly 70% of the world's LNG demand, and we do expect strong demand pull from the region between now and 2030, as you heard from Patrick, softening prices with additional demand from price-sensitive countries such as India and Southeast Asia that is precisely what we have seen in past cycles. To the right, we show the expected growth in our own LNG sales. And as Stephane told you, we have signed 4 million tonnes long-term contracts with Asian customers this year to date, and there is more to come. These contracts are largely all indexed. So in summary, on our LNG sales in Asia and strong growth with good price formulas. Next chart, please. Moving on to India, which is a good illustration of the opportunities I mentioned, linked to developing as opportunities and growth around our 2 pillars of LNG and renewals. We're well positioned to capture growth in the Indian LNG market, thanks to our participation in the infrastructure for LNG imports and in the city gas developments together with Adani. Likewise, we have a strong presence in the Indian renewables market by our 20% shareholding in Adani Green and via the direct participation that we have in asset-owning JVs where we invest 50-50 with Adani Green. These JVs totaled 4 gigawatts of capacity at present. India is gradually liberalizing its markets, its power market, which enables us, therefore, to selectively grow our urgent exposure that Stephane was just talking about and which is clearly part of our value-creating business. I also want to stress that India plays an increasing role a state-of-the-art competitive supplier base for us, paid for equipment such as PV modules, EPC contracts or digital services. Next chart. And now our last chart, just on Malaysia. As you know, we are about to close the acquisition of Sapura OMV, which has a sizable gas producer in Malaysia and the operator of the [ PSC SK ] followed, we're talking about low cost, low emission gas in line with our insulin criteria, of course. This operation will add some 50,000 barrel equivalent to our production as early as 2025. And we also have a good platform for future growth coming both from existing discoveries and future exploration. So we're excited about this acquisition. And it will, of course, also consolidate our long-standing partnership with Petronas with whom we have multiple JVs around the world and also a recent partnership for CCS in Malaysia. And with that, I will hand over the floor back, Patrick. Thank you.

Thank you, Helle. So the digital works with TotalEnergies, the connection both in New York and Tokyo was perfect. We have already had to spend a lot of coming back to New York for 10 minutes, and you have been perfect, Helle. Thank you for sharing these ideas with us. So to come to finalize, to conclude, why should you continue to increase the investment in total energies, business case? I think first, I remind you that we have some fundamentals which are strong, in particular, the breakeven of the company before dividends, $25 per barrel. It helps a lot of us when we consider potential volatility on the oil price in coming years. It's a fundamental, which allow us, of course, to -- and it's linked as well to the second characteristics of the portfolio, which we have aggregated is that we have -- and people sometimes see TotalEnergies as a resilient company to low price, but we are also capturing price upside. You can see that compared -- we have moved the portfolio to much more higher cash flow per Brent -- per barrel of Brent, I would say, and we can compare the performance of the year '21, '22, 2022, '23, '24 compared to the same Brent price the performance before up to 2004, 2018. So that's the second point. And all that has underpinned higher shareholder returns. We have taken a commitment since last year that the payout ratio should be above 40%. We delivered more than 45%, 46% last year, 48%, '23. We are above 45% for this year as well. What we described to you is the same slide I introduced at the end of my first part, so I will not comment it again, but this is the energy -- I mean, this is transition business model of TotalEnergies. We grow our energy production. We diminish our emissions, including the carbon intensity of our energy sales. So we are transition business case, I would say. And we'll deliver more free cash flow, and I hope the presentation of Nicolas, Stephane and Bernard convinced you that this additional $10 billion of free cash will be material and have some clear -- I would say, ground strong reasons to be presented to you today. And again, I insist that even if the price of $60 per barrel, the additional free cash would be $5 billion, so you can see the impact of the sensitivity. If I'm translating all that, and I know [indiscernible] in the room and Renaud they love this slide into cumulative free cash that Total will be available, we'll be able to share with, I would say, its shareholders and which will support growing distribution. We charge or -- so it's '25-2030, it's 6 years of cumulative free cash. I'm commenting further on at $50 per barrel. On the period, we are, I would say, the CapEx as around $100 billion what we presented to you. In the $50 case, we have considered -- but we could -- if it was really 6 years at $50, I think we would exercise, of course, the flexibility we have done well. So it's a little lower than the $100 billion. We add on it without growing it in this chart. So it's just a 2024 dividend, the existing dividend, which represents more or less $7.5 billion, let's say, $46 billion on an annual basis. On a 6-year basis, with no growth. But of course, not intend, there is no message there, you will see. It's just a math to show you that we have space not only to increase the dividend, but to also maintain our shareholder return. So the first message on the left is that, in fact, our post dividend breakeven is lower than $50. It will be in '25, I think is around $45 per barrel. So keep that in mind. And so we are lower than $50. The second one at $80 per barrel, it's that we will generate $10 -- more than $110 billion of free cash flows. At $60, it would be $80 billion. So of course, if you make some dividend growth. And you have -- you can see some math that we could continue to maintain at $80 per barrel. We could continue to maintain the I would say, $8 billion per year program that we have put in place consistently for the last 10 quarters. And there is even more if you make the math for improvement. So improvement the dividend spend and maintaining at least the $1 billion buyback program. And that leads to this chart, but you know quite well. We do not change the order, and I just wanted to comment you which is a way that the Board looks to the cash flow allocation. First, of course, the dividend is our primary, I would say, to maintain a sustainable ordinary dividend for cycles. We didn't cut the dividend by 2020. I should say, by the way, when I was looking to the figures that since compared to pre-COVID dividend, we have increased it by 20%. We are second in fact, in the industry. There is only one U.S. company, which has done a little better. We are doing better than the overall U.S. company and far better that our European peers, we have diminished by 25% compared to pre-COVID dividends. So we have done 7% in the last 2 years. Today, what I'm telling you is just applying the policy that the Board is committed to, which is, in fact, the next year, which will increase at least by 5% dividend because we'll buy back in '24 more or less 5% of, I would say, of our shares. So mechanically, we'll increase it at least by 5%. We'll take the decision about this increase by February. So we keep some the Board to decide according to, I would say, the final results of the year and the perspective. The CapEx, I commented that. The balance sheet is strong. We have a 10% gearing by the end of the first half. There is a working capital build on which Jean-Pierre and all the -- my colleagues are going hard to diminish it. We should have a build of working capital this year because last year, because of the high prices, we benefit, I would say, from $2 billion of exceptional decrease of the working capital, some linked to fiscal positions in different countries, but we should have some diminishing of this working capital before year-end. And the last one is the buyback. On the buyback, we have consistently bought back $2 billion per quarter. So I confirm you that we'll maintain this $2 billion for the last quarter, and so we'll buy back $8 billion this year. And we have -- the Board, we decided to announce you today that we'll continue on this pace of $2 billion per quarter in '25, assuming reasonable market conditions, it's better than current market cultures, lower, I would say, than current. So that's the discussion. Because why? Because we know that investors are looking to are to appreciate this buyback from oil and gas companies. And second, because again, the gearing being low, we can, I would say, leverage with gearing in order to maintain our pace of $2 billion per quarter in '25, assuming reasonable market conditions. All that, again, will lead to maintain this more than 40% payout through the cycles. In '24, we should be above 45%. So we have a performance, I would say, which share of TotalEnergies has done well in the market. We have an earnings per share, which is a I would say, compared to our peers. So it's quite good. And we have a TSR as well, which has since we take the last 10 years, has offered good returns to our investors. I take just 1 minute to comment on this slide. As you know, we are working on a project, which is to transform ADRs into certificates, which are today the base of our U.S. listing into ordinary shares. So we are already listed in New York. We just want to transform these ADRs into ordinary shares because it simplifies management for our U.S. shareholders, removing some ADR frictions. And it will be likely to improve the liquidity of the TotalEnergies security. Just to be clear, because I know that what I'm saying today will is listening in Paris. Paris will remain the TotalEnergies shares introduction market. But we are working, so it's a work in progress today, on all the technical aspects with both European and U.S. central securities depositories Euroclear and TCC. The Board supports unanimously these projects of transforming ADRs into ordinary shares, if it's technically feasible because it requires some IT development and certain delay to be operational. So it's a work in progress. If it is technically feasible, we intend to make this transformation. I remind you that ADR represent 9% of the shares of TotalEnergies today. So it's more a question of being able to offer to U.S. investors, I would say, an instrument which is easier from a financial point of view, from an investment point of view, like our European investors, and it will not be a revolution. But of course, it's contributing to the liquidity of total energy security. And finally, to conclude this presentation. And to summarize what we said today, I introduce it. This slide is conclude it. We have, I think, a very deep portfolio of upstream opportunities. coming from both exploration, which is strong, which is good, like Suriname, and I know that all the teams in TotalEnergies are very proud of the Suriname project, but also from some targeted M&A we have done in the last years. It's now offering a de-risked, I would say, high-margin growth perspective to our investors and starting from 2025 -- we have bet that through strong on LNG market. And we consider for the long term, it's quite a strong position, and we are de-risking the exposure to spot gas to manage the LNG wave we will face by the end of this decade. Our Integrated Power business is developing its interested business model. And again, I insist on the role of gas in our strategy. because fundamentally, this is the link we consider that natural gas will be one of the transition fuel coping with renewable intermittency, but also being able -- enabling the decarbonization of part of the power cycle as itself. We have some fundamentals, disciplined CapEx and OpEx. We are a low-cost operator and portfolio. Breakeven is controlled and a strong balance sheet, and all that, all in all, allow us to, again, consider that we'll continue to grow dividend and sustain share buybacks for the year to come. Thank you for the attention, and we'll be happy to answer to your questions.

Okay. Let's move to the Q&A. So the rule is very simple as usual. You raised the end. So Michele raise the hand already.

Thank you very much, and thank you for insightful presentation. There were two questions to ask. One, which partially relates to recent news flow, we've seen a bit of an emergence of fiscal instability again in Europe. We had a change to the U.K. taxes and now we have some announcement in France wondering if you had any comments on that or any potential quantification of the impact? Secondly, I wanted to ask you on technological innovation. There's a lot of questions about AI digitalization, how it changes the sector I think you were presenting at the SAB Digital Day last month. I was wondering, do you see this just as an evolution of what has been an ongoing improvement in efficiency? Or could this be a breakthrough, especially in recovery rates and discovery rates from a seismic and exploration perspective?

Interesting. The first one. First of all, I was in Suriname I listened to the Prime Minister speech yesterday. There was no big announcement, they said that they want to unfortunately to increase taxation in [indiscernible] in France rather than cutting spending, which I think is more expected by markets you should go and explain. But on our side, I would say, first, two comments, the income tax is based on the revenues in France for TotalEnergies. As you know the magnitude of it. It's quite limited. So I don't expect much impact on us. Second, there is a debate about buyback taxation. And according to what I know, what is considered even if it's a little constituted different for different reasons, level of the 1%, which is today applied in the U.S. is considered as a base of the discussion today. So honestly, you can make the math for us. It's around -- it will be 1% of the buyback probably. But even it will not be express like that because they are more willing not to tax when we buy back the shares, but when we reduce the capital. So there are some technicalities. So the percentage which might appear in the news will be higher. But in fact, at the end, it will be sized to be more or less in line with the 1%. And it's difficult for me to argue against it, as our U.S. taxation as it happened. That's where we are. So the situation in the U.K. is much more problematic because it has not only a higher impact, but there, I'm taking that very seriously because clearly, we'll be very selective on any CapEx we will spend in the U.K. And we are clearly looking curiously to way to restructure operations. So for -- it's very different -- France, it's not an oil and gas country. So honestly, it has limited impact on our businesses, I would say. On the U.K. part, it will have an impact clearly on our U.K. investments if -- we are waiting for the October 30. There will be a big speech by the Prime Minister or the Chancellor in the U.K., which will impact, of course, the follow-up on the position, and what will happen to us on our position in the U.K. I'm arguing with them but they should copy paste to the Norway [indiscernible] system, which is maybe high fiscal, but incentives to invest. If we lose -- if we have the high fiscals without any incentive to invest, I'm afraid the production in the U.K. North Sea will diminish quickly, which is not the interest for me of the country, but that will be the choice, and we will respect the choice of the country and draw the consequence for our business there. Technology; for me, there is -- something is happening. It's a revolution in particular, in terms of speeding up I was convinced by a discussion with the head of French methodology. We explained, that the model of methodology, which was running 5 days before today, it's 1 hour. And Google becomes probably one of the best because of AI. So there is an evolution. So in fact, it's feeding and speeding more than, honestly, I'm not -- I don't think will discover oil alone in the ground i was really surprised. But speeding and in particular, designing projects. I'm sure that today we spend quite a lot of time to view and to review. And not only we should more copy paste what contracts [indiscernible], but even and reinvent the wheel in many ways, I think with this type of tools, which should be able to accelerate the process. And so for me, it's something and there is a new thematic. In fact, in our company, we have done a lot historically on subsurface data. We acquired -- we spent a lot of money, so sorting data, managing the data modeling, using them. And we should know -- we should [indiscernible] think in our companies to do the same on the digital plant, the digital plant will be for me a source of efficiency. We were speaking about fighting inflation costs. This technology should help us to accelerate on it. So it's more using shortening the time if it can -- but again, somewhere in your question, I'm convinced that reverse modeling. When you speak about physical models, which are not so efficient -- if you have a lot of data, you can make some reverse modeling and reverse modeling by AI could be -- could deliver to even to Vincent in his refineries -- all the models, linear models are not so efficient. We could be much better if we are able. But to do that, we need to have digital plans to acquire the data. So that will be an axis of investments. and we are working on it for the next year.

This is John Abbot from Wolfe Research. I'm here for Doug Leggett. We had a couple of questions on Suriname. Could you explain the $1.4 billion plateau at $50 oil? Does that include capital cost recovery? And can you confirm whether or not you might have gotten better PSC terms at FID? And then for our second question is, you've talked about a 4-year plateau. What's your visibility on possibly extending that?

Yes. First, yes, it includes a cost recovery, obviously, which will be recovered in 5 years at a reasonable price. Yes, we have improved some terms. Yes. Now in particular, what we insisted on it, there are several items. So I will keep that within the authorities and ourselves. In particular, we -- we have, I would say, better terms when the price is under $60 per barrel, just to protecting the robot. And secondly, which as important images, we have large development areas, and we will be able to amortize all the exploration on the first projects that we could go tomorrow. Why is it important? It's linked to the last question you raised, which is, can you extend the plateau? Yes. There are like it was said by Nicolas, some targets 50, 100 million-barrel of oil, which are facility of this up. For me, the Grandpuits will become a hub. And as we can amortize more exploration, we made other discoveries in that block, but will incentivize us to look again with discovery. So I think we are in a good position, yes, to extend. Clearly, we see some upside. And secondly, to maybe develop more resources in Suriname. So we negotiated terms, which are in the interest of both parties.

It's Martijn Rats Mason, Morgan Stanley. I wanted to ask you two things. First of all, on the buyback guidance for 2025, you mentioned assuming reasonable market conditions I know it's an impossible question to answer, but you can see where this is going. Could you sort of elaborate a little bit on what the boundaries of reasonable market conditions are. It sounds like sort of $70 Brent, but of course, other things like refining margins also play into that. And then secondly, I wanted to ask about Namibia. It was a figure of 160,000 barrels a day of oil on the screen. But I was wondering how much comes along with those 160,000 barrels? That one in particular.

Okay. On the first one, I don't know if you have asked a question to our peer who was exactly use the same sentence assuming reasonable market conditions. It's -- so $70 for sure. But in our mind, it is a [indiscernible] we have -- it's lower than that, okay? We can sustain this $2 billion per quarter. You are right. It's a combination of oil gas refining margin. But generally, when we're all going down, the refining margins are better. So I would be surprised to have everything going in the same direction. And as the gas price for me in '25 should remain more in the range of this -- what we experienced today. I'm confident about it. So we could -- it's lower than $70 in the mind of the board, and we discussed it with different scenarios, precisely. So just to answer to your question. So that's why I can say today, $2 billion a quarter in '25, you can take it as an assumption then, of course, if we are at $50, you will see us moving, but it's not reasonable market conditions, okay? Second one, the gas -- is there is gas. Again, the gas story is not a matter of -- it's a matter of being able to ingest all this gas in the reservoir at cost, which is acceptable. There is the GOR of this [indiscernible], for example, compared to Suriname is here. In Suriname, we are reinjecting the gas and we do it with acceptable costs. There, you have a higher GOR. So that means that the machines are to reinject are higher. And you need also the reservoir needs to absorb this gas, and we don't want to flare. So that's where -- it's a combination for me of costs and this gas where we are working on it. Remember that it's $20 per barrel, or less than $30 breakeven, which are our objectives, so we have ways to accommodate it. We might engage into discussion with the Namibian authorities, like we've done with the Suriname's authorities. We have the advantage in both sides to be the first mover. So the first word is quite welcome and answering to your question. it's easier to discuss a bad condition when you are the first mover and maybe in the natural numbers, we're the only one, the large ones. So that's where we are working on it. So that's what I can tell you today.

Paul Cheng, Scotiabank. Two questions. Patrick, I think in the past, you have said Total know how to sell gasoline and diesel but is not very good in selling think and all the other products. But in here today, you're saying that you're going to leverage your France position and trying to do far more in the nonfuel sales. So why that you think, given your previous comment, that you have the -- maybe the tone and the know-how to be in that business to be successful? And given people are still willing to pay a fair money for the marketing outset, you say better for Total, perhaps that to take this opportunity to scale down in the funds marketing and monetize the asset? The second question is Mozambique I think you're still talking about 2029 yes, everything is all said on the renegotiation on the cost and everything or that you still have hurdles before that is really a good set in stone deadline?

No. But I mean, first, you know we made a JV. We sold some assets to [indiscernible], -- we made a JV in Belgium. So we are learning a lot on this part of nonfuel cells, and we want to apply what we learned from this Belgium JV, including in France. No, we do not intend to divest our French marketing assets -- probably clear. It is a strong position. We have 22%, 23% of market share. It's a profitable one. What we want to do is to continue to benefit of it by again accelerating the of sales, and we are learning, and we see some position, but it's a strong position that we value. Honestly, being what we are in France with the size of the company will be difficult to not manage ourselves this business. including for French consumers. The Mozambique. No, I think we be clear, I think I commented it in last call in end of July. On the contractor side, everything has been said, including the cost of the frozen period, it has an impact on the cost of the project. I think one of our peer partner mentioned $3.54 billion. But this project remains profitable because there is a portfolio in particular of LNG sales, which is quite attractive. And so we are committed to the project. On the security side, we are -- there are some progress on the ground. You know that Mozambique as an alliance, we have [indiscernible] on it. There is a new -- there is an election -- an Mozambique, a new President will come. I intend to visit Mozambique by the end of the month, myself, to meet him, to discuss about the way -- they intend the new Mozambican authorities intend to maintain this alliance with [indiscernible]. And then we are working on the last piece in order to be able to restart the full projects is the financing of the project. There was -- when we inherited the project from [indiscernible], there was quite a big financing age. I think it was almost $14 billion. The different ECAs, I would say, 70% or 80% of them have confirmed after due diligence that they are committed to that, and we are waiting for three of them to confirm as well their commitment because it's important. And some of them are in country, western countries where in between, I would say, the stance towards financing of LNG projects or oil and gas projects have moved, but all of them are telling us repeating us that they are committed by contracts they sign. So we are waiting for the green light on this financing from these three credit agencies. I hope we'll have -- we'll get them soon and as soon as all that is in place, we tend to restart the project. So the 2029 target, which is on one slide is linked to restarting the project by, I would say, year-end 2024. So we see -- where we are today on this project.

Thanks for the presentation. Two questions. The first one is on the $2 billion of CapEx flex you talked about. Could you just articulate a little bit more on where -- which divisions that would come from and how you think -- how we should think about that flexibility there? And then the second question is on dividend growth. You referred to the at least 5% in line with the shares bought back. But you're also putting forward a story around growing free cash flow and growing free cash flow potential. So going forward over the medium term, should we think about dividend growth at a minimum to be in line with the shares you bought back in the prior year. Is that a fair assumption?

But we've done it.

Going forward? Is that fair?

Yes, that's a rule. Yes. To be clear, the Board is quite clear that when we bought back, we intend to grow the year after the dividend at least that was put back in order to maintain at least constant, I would say, the $1 billion in terms of absolute amounts, we could decide because we have a perspective of growth to go beyond, like we've done with the 7%. So last 2 years, we grew it by 7% in Europe. By the way, it was 8% in dollars, because we capture it by growth. Part of the perspective of growth. The Board is confident about these figures. So there is a floor, I would say, which I'm repeating today and translating it '25 when the Board will appreciate. Again, normally, we take the decision by February board because we prepare the next AGM, and we did not accelerate today. We worked more in the proprietary work to this investor presentation. We spend more time on the buyback perspective because we knew that people were expecting from us to take some stance on it. So I think we have delivered to you a clear message on that. And again, on the dividend, yes, we are committed to that. We don't intend to spend money thanks to the buybacks on the dividend amount. In fact, probably, as we've done the last 2 years, we intend to grow it in an absolute term. And the other question, the flexibility. Flexibility, it's -- of course, it's a different ways to look flexibly. I remind you that in 2020, when COVID came, we find $4 billion of savings in the CapEx you have flexibility. Of course, it could be some, I would say, short-cycle projects drilling infield wells, which could be deferred if we had to do it. We need to look to what is the impact and the choice between production and that. But -- and again, I think that I don't see that as being immediately done, I said it's $50 per barrel, less than $50 because we are -- again, the balance sheet offer us the possibility to maintain or, I would say, our CapEx program. But one of the exercise, which is done -- because the way we work each time we prepare budget and would be done for '25 -- colleagues, they will come with a base program, which is based on the figures that I mentioned to you. And then each of them is supposed to identify what do we do at $50 per barrel or at $40 per barrel in terms of CapEx. So we'll have different options. And then we'll see which ones are in our eyes, the most efficient ones. So it's coming from different -- all the divisions are concerned by the point and not only Nicolas, but everybody will be, will have to activate. But we have the flexibility. It's already not, for example, in '25, part of the CapEx -- organic CapEx are FID, we did not yet have taken. We have pre-FID CapEx in that program. So if we want to defer 1 by another 6 months or a year, we could do that. We have a growth we have some flexibility. I think 1 of the comfort we have is that the depth of this portfolio is quite large. We have optionalities. And I prefer to be in a position to have more options and to be able to defer some of them if CapEx are not there or if not to overstretch the company on the contrary. So it's a better position from the CEO to have more choice than being obliged to look for additional reserves. We have that in the portfolio. Let's go in the middle Giacomo.

Thank you, Giacomo Romeo, Jefferies. I can look at -- if I look at Slide 53, where you show your cumulative CFFO, you talked about this $60 billion on top of the existing dividend of excess cash flow generation. And you pointed out obviously a current rate of the buyback, I assume it's 48 million in that time frame. It's -- how do you think about distributing that extra cash flow. Biraj asked about growth in dividend that's where actually -- how do you think about allocating between buyback and dividend? And in the past, you paid a special dividend is that would you consider that no longer on one of the options you'd be considering? Second question is thank you for the update on the U.S. listing or in the past, you talked about thinking to move the primary leasing in the U.S. Has that option completely dropped or you will keep that?

I never said that. Don't believe with what a new press on agencies say. I never mentioned that. So to be clear, it has created some move. The project, as I said, is to transform ADRs into ordinary shares. If we can do it, but it's linking -- in fact, the U.S. the French market and the U.S. market, so that the shares could circulate, but it's quite -- it will improve liquidity, but there is no at all to move any primary listing. Paris remains the market to introduce shares and we'll keep the quotation in France. okay? And we will remain from SEC regulatory point of view, a foreign private issuer. We have already, in fact, all the regulatory burden moving from ADRs to ordinary shares does not change anything from a regulatory point of view. So that's why if we can improve the situation for investors would be good. Could have access to ordinary shares and not only ADRs, which I understand, when we make some discussions with them, generate some friction, some additional costs and some of them do not like this idea -- that's more the point. So again, it's transforming ADRs into ordinary shares. It's a technical project. It's not a giant political project.

On the distributions?

On the distribution. So first, special dividend, to be clear, we were very clear. We have done lit and it was really linked to an extraordinary situation of extra -- I don't like to say that, but not extra profit. Extra cash flows, we made $48 billion of cash flows in '22, '22 compared to today, it's around $30 billion, $35 billion. So it was, I would say, a situation -- and so we decided to share this extraordinary situation through a special dividend. So don't consider it's a normal instrument. It's an extraordinary instrument, I would say, to extraordinary situation. Your math has good -- math are good. So I think my view is that we should -- will work first on, as I said previously, as we grow the dividend quicker than the last years than only the buyback, you should have not only a stable billion of dividend, but it should grow. So that's part of it. So if you go from 8x to $8 billion per year to $9 billion per year, you would consume part of it. On the buyback, I consider that $8 billion I like the consistent policy to repeat to repeat to repeat. So for the time being, if we have -- if we deliver first, again, be careful, it's an assumption that we remain at $80 for 6 years. It's just in Excel, but you see that. And so my colleagues, they love Excel, they calculate with Excel. Life is a little more different than that. You could have more I've never seen the flat even if we experience this for almost for 2 years, '82, '83. So we have experience. But -- so it's just to give you an impact -- a size of the magnitude of what could be generated, gives me confidence. But as I said to you, we could -- we could maintain the buybacks, and we could also grow the dividend. Okay.

Chris Kuplent from Bank of America. Patrick, I have a question that feeds like a question I should ask over lunch, but I'm going to put you on the spot. And it's regarding your macro consumption, you just mentioned 80 Brent for 6 years. You've attached to that $8 per BTU and Stephane in your presentation, you also gave 60 at $6. So maybe I wonder whether you could comment a little bit about the dislocation we've seen this year in JKM DTF versus Brent and how that's potentially impacted your view brand slopes as you continue to sign new contracts as you've shown. And secondly, the more trickier question, which one of those 80 Brent or $8 TTF, do you think carries more or less upside risk?

Upside risk. I'm sure to understand the notion of upside risk.

Which one of those do you think is more bullish?

By the end of the decade, the $8 is more bullish than the $80, clearly. Because again, I'm facing the reality. I think that TTF could go down to $6. So my combination personally, I mean, with the Board was $80 Brent and $6 gas. It does not impact you have the sensitivity for $2 per 1 million BTU, it's $400 million of cash. So multiplied by this year, it would make $3 billion. So it will not change fundamentally the cumulative free cash. But to answer clearly. No, effectively -- on the oil, again, we face a situation where the demand continues and the investment is lower than before. And so on the gas, we'll have to manage this capacity wave. So I mean -- I'm and we have experienced that in the past. And I think, again, I'm not afraid because it will -- but I'm not afraid because it will foster the demand, and I'm not afraid because as we decided with Stephane we move to the Brent, the beauty. But you could ask me why then -- so you have customers signing this type of contract, Oh, but because they expected what happened in '22, '23. And they are not sure again? Because some events could happen. And in this world, we see some more disruption against supply and against demand. So that's why I think the same. And yes, we the slope, we have an impact. We have some guidelines on what we want to do. As it's also important, Stephane could complement and insisted in his presentation, it's not only Brent. It's a capacity to arbitrage the optionality we have in this contract, which is important for us. So of course, you have an arbitrate which will cover aging with, I would say, a brand formula, but what is the amount of optionalities you keep if you want to benefit from other dislocation of the market. And I think that's why the teams are working on. On the first one, you wanted maybe Stephane and me to comment on the dislocation that you observed. In fact, JKM has been, yes, higher than the plus $1 became plus $1.5, $2, I think. So there is more demand on this side. Maybe you want to comment it?

Europe is consuming less gas and now China and India is consuming much more, and we see a very interesting thing in India actually. So that's one. Second, it's clear that the logistic issue in Panama and Suez has not helped has triggered an increase of the gap. Now if you look at the forward curves, you see that the dislocation is diminishing in '27, '28. So all the markets fundamentally see what we see. And just last comment. The $8 gas is a TTF-1. It's not JKM. That means that it's not 10% Brent slope, it's a bit above. And we are clearly signing above.

It's Lydia from Barclays. And I've got two questions, if I could. Patrick, you presented a really compelling story here. You've got 4% growth in energy production. We've got $80 million to $110 million of free cash flow. You could buy potentially back up to 30% of shares over that 6-year period, and you've got an incredibly compelling team to kind of go through and execute that. So what worries you, if I put it that way, as to what actually bothers you? And what do you spend most of your time thinking about? And then secondly, I think the phrase you used a few times was copy paste. And how much in practice is that actually saving you? And are all contractors as open to it as for example, your existing ones versus some of the new ones you're bringing in?

The copy paste, I mean what we've done on Suriname, we are able to sanction it 1 year after appraisal because we took a strong decision to consortiums with Namita and Nicolas, but if the design of SBM was good for our nice friends, big friends next. I don't see why it should be not good for TotalEnergies. So I'm -- sometimes you know we know I know I have the best engineers in the planet, but we are very strong, and so make it as a difference and it concluded that it was okay. So it accelerated. And of course, for the contractors for the contractor himself, they see an economy of scale because it's an additional one, and we try to replicate it on Namibia with the difficulty of the gas because if we have to have a big gas machine and doing 500 million square per day instead of 200 or 300 million, of course, it changed the dimension, that's the limit of it. So I think it's more time to market and being efficient and giving a chance to the contractor to benefit with economic scale and during the different contracts. So I'm convinced on some topics. It works Petrobras is doing that. We have service in Brazil, but in the Sepia 2 and Atapu 2 and all that. At the end, we have, by the way, 2 FPSOs. It's the same. So it was we applied it with Petrobras. And so if Petrobras can do it, I think we can do it as well on some topics. That's another point because we face an inflation in our -- because it's now $80 per barrel, the service companies contracts they want their share of the cake. So we need to be creative if we want to manage this inflation. What will be the worst or what worries me. First, the world, honestly, the global world is strange and dislocation, rupture everywhere. So I have experience in 10 years of CEO, some incredible events. The COVID, the Russian war. I know that unfortunately, again, Excel and wth linear way to present the things will not happen. So I'm paid for that, so to be -- to look around and to say -- then the other part is we have a big -- we have a lot of things to execute. Part of it is operated, Part of it is non-operated, so I think the spread. So it's really being able to execute these projects. And -- and some of them -- and vision, I think for me, we are clearly Suriname. It's exactly the now of the company, deep offshore, operated. We have other projects onshore which are more complex to execute because we face more difficulties with stakeholders, et cetera. So that's, I think -- and there, on our side, what we should do with the management is to be sure that we have the right person, at the right place and that we have enough on the ground. So it's more execution of all that. Okay. I would say. But and then facing a world which clearly is becoming more complex for global companies because you see some fluctuations, and that could have impacted some impacts on our [ indirect ]. So I'm expecting the unexpected -- to a bit clear.

Jason Gabelman from TD Cowen. A couple of questions from me, first one, hopefully pretty simple. On the free cash flow growth of $10 billion, I'm wondering if that incorporates any decline in CapEx because it looks like you have higher organic CapEx earlier and then lower later? And then what does that kind of imply for the free cash flow trend over that period? Is it more modest early on and then greater, longer out. And then my other question is just thinking about buybacks moving forward and you had historically talked about a net gearing target. It used to be 20%. I think earlier this year or last year, it was down to 10%. Now it's kind of gone away. Is that still a relevant metric as you consider how you manage your balance sheet and distribute cash to shareholders.

No, we normalize it. I mean, I'll be clear, we took a -- we gave you a range of CapEx of '16, '18. So we took '17 for the calculations. So if you consider compared to '24, where we are around '17 '18, there is not much impact on the free cash from the CapEx. You have maybe $500 million, $1 billion, let's say, maximum. And that's why we saved more than -- 10 you can consider [ 10 ] as without any positive impact on the CapEx increase, just to take to be transparent on this one. Yes. I mean, we cannot give you -- I mean it's more complex than that reality. There is some flexibility in the balance sheet. If we are using -- if we told -- I answer to you, it's lower than $70. That means that I'll let you make your model, but you will see that, of course, if I'm continuing to buy back $8 billion at $65, that means that the gearing will go up. It's not 10%, obviously, it's not 20%. It's in between. Somewhere I think, again, things are not happening linearly, unfortunately, in the world. So you can -- it suddenly you have a war on the oil price, and you see a crash like in 2020, where do we go? But in 2020, we demonstrated you by keeping the dividend intact and managing the CapEx downwards, but we accepted the gearing to go up above 20%. We accept it because we think because we are also convinced this type of situation do not last for long. It's a matter of -- and we are in a much more comfortable situation with a gearing of 10%. So yes, we will accept to have a higher gearing in order to do it. But -- it's a debate. Again, we find, I think, a positive message to you investors about the buyback is we maintained the $2 billion per quarter a reasonable market conditions. So with that, you do your math.

We can take questions from the online maybe.

Oh, you choose. You are the master of ceremony.

Okay. So Matt from JPMorgan.

Thanks, everybody, for taking the questions. Two quick ones, if I could, please. First, just following up on the previous comments on cash return -- you've emphasized keeping the distribution of cash flow above 40% of CFFO. It does feel to me though that there's a greater propensity to distribute higher than 40% and use the sort of the mid-40s for example, if it's necessary than was the case in the past. I wonder if that reflects the successful progress in derisking the multi-energy growth proposition over the course of the last 1 to 2 years? And if you could comment on that. And then secondly, on LNG, the hallmarks of the business in recent years has been, I think, the ability to flexibly deliver between regions and particularly between Europe and Asia. You showed, I think, on Slide 47, increasing contracting into Asia over the sort of the coming years. how do you think about the best and appropriate balance between increasing that contractual commitment into Asia versus maintaining the optimization flex between regions?

Okay. Now, to be clear. You notice that you make the math, $8 billion of buybacks commitment like we've done with our dividends at $80 per barrel. You are more at 45%, but at 40%. But the 40% guidance is through cycles, which means that it will apply also at $50 per barrel. And at $50 per barrel to keep 40% -- make the math, you will see that we need to make some buybacks as well. So it's a guidance -- is through cycles, at least, yes. So there is no change. It's true that at $80 per barrel this year will be, and again, $8 billion plus the dividend, which is more or less $8 billion, so $16 billion out of $32 billion of cash. You are more around 45%, 46% than around 40%. But the commitment is through cycle. That means that we will keep it 40% guidance at $50 as well. So we don't change it at $80, even if in the fact, reality, what I just told you, it's true that at $80 more 45% plus than 40%. You can answer, Stephane, but keeping your optimization.

Yes. The truth is that it doesn't lower my capacity to arbitrage and to optimize because typically, I take a U.S. cargo, I sell it on the Brent index in Asia -- nothing prevent me to buy back the LNG. I need to make myself in Asia based on JKM and to send my cargo in Europe to see on TFF. So it's not because I'm selling in Asia on a Brent index that have lowered my capacity to arbitrage TTF. I could even argue that actually I'm extending my capacity of arbitrage between Brent and JKM. The only thing that I need is the fleet and the regas because I need to be able to go in Europe when I want to go in Europe and the good thing is that I've got the largest 3 year capacity today in Europe that I'm using.

The fleet, we should increase. So the point is that today, we have the regas, no problem. The fleet. We need mentioned the fleet, but it was in our plan. According to the volumes. So we cannot have more volumes without a larger fleet. So we are just trying to understand when is it the best to commit on the fleet. And so there is a monitoring by our shipping VP, who is coming to us regularly to ask for more LNG tankers, but we know that we have to dimension the fleet according to the volume.

Can I ask two things? On the Integrated Power, can maybe probably for Stephane, can you talk about the amended exposure to power prices? So we're using $8 gas if it comes down to $6 and prices are set by the marginal cost of fossil fuels, what does that do to the $5 billion of cash flow? And then secondly, I'm going to direct it to the screen is still there. I'm sort of interested in observations on China oil demand this year given the high EV sales is someone on the ground, what is she seeing that perspective would be useful?

Not yet. It's still alive still not yet. I don't know what time is it in Tokyo. You don't have a little loss today. So I'm -- it's quite late. But -- so I will give the floor first to Stephane explaining how it works in the integration going from A to Z.

Yes. So it's a bit difficult question because actually, you don't have 1 power price. You have plenty of power price depending on which market you are looking to. That's one. And second, on the $5 billion cash flow, part is coming from renewable, which is exposed for the merchant part to the wholesale market price and part is coming from the flexible asset, typically the CCGT, which is more the difference between the power price and the gas price. So it's not because power increase. It increased because of gas at the end of the day, it is still making the same thing. So you can't expect to have the same sensibility in the same way we talk about crude. That doesn't work. I didn't say so, Today, our sensitivity is limited because clearly, we still have a merchant exposure that is not that high for the renewable part on CCGT that's more the case. And by 2030, we are probably talking on the $5 billion, $11 million, $25 million of flexibility depending on which index you will look at. So it will be positive to price -- that's all.

Any other questions?

One thing which -- in the integration, just to comment on it. When the gas price is going down, the electricity price is going down. And suddenly, you have [Foreign Language] parachute, a parachute effect on all your consumer business that we experience today. In '24, we made quite a lot of money in the electricity with the consumer portfolio in France. Because you price -- you are pricing -- you benefit from the fact that you are pricing your electricity with a risk premium in advance. So that's why we discovered that, in fact, we have a nice chat and we'll come back when they review the figures. In fact, the integration helped us to benefit from one part of the portfolio if a higher gas price is not good for CCGT, but it's good for my integration upstream, et cetera. So you can look at it. And honestly, the more I'm looking to [ visit ] electricity business, the more I see some good integration with -- if you are along the value chain with our gas business and not only renewables business.

Okay. So Irene.