Ladies and gentlemen, welcome to TotalEnergies' second quarter and first half 2024 results conference call. I'll now hand over to Patrick Pouyanné, Chairman and CEO, and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead. Good morning or good afternoon, everyone. Patrick Pouyanné speaking. Before Jean-Pierre will go through the second quarter financials, I thought that this year would be a good time to check in on the progress that we have been making. I would say the great progress in just the last 10 months since we presented our strategy last September at our Investor Day in New York, or I would say balanced transition strategy, which is anchored on two fundamental pillars, the oil and gas on one side, with a perspective of growth, and integrated power on the other side, and both our growth pillars are driving the growth for the company. So during this last first semester and last quarter, beyond the excellent operational performance, which was delivered on our oil and gas pillar, we have sanctioned several major upstream projects that I would like to remind you. On the oil side, with the financial decisions on three large FPSOs, Kaminho in Angola, Sépia-2, and Atapu-2, and both which are world-class oil productivity projects with low technical operating costs under $20 per barrel sanctioning criteria, and Angola is under $30 per barrel breakeven. So these are three major oil projects, but we also have sanctions on the LNG side. Two important projects, the Marsa plant in Oman, Marsa LNG, which is a very ultra-low emissions plant, and the Ubeta gas project in Nigeria, which will supply Nigerian LNG. So these projects will not only contribute to the objective to grow our upstream by 2%-3% per year in the next five years, but they will also boost the underlying free cash flow generation and ultimately shareholder distributions. On the second pillar, integrated power, where we have reached a, a quite competing ROACE above 10% this quarter, and Jean-Pierre will come back on it. We have also made some strong progress towards deploying and completing our integrated power business model by acquiring flexible assets that allows us to extract maximum value for the, from the renewable assets. In flexing markets, in Texas, in the U.K., and in Germany. We closed our CCGT deal in Texas and also announced the acquisition of a CCGT in the U.K. Both of these markets, we know have all building blocks that define our integrated power model, renewables, flexible assets, and of course, trading and, and customers as well, in order to deliver clean firm power, which prices at a premium compared to a green intermittent renewable power. We also acquired flexible assets in Germany through our acquisition of Kyon Energy, a leading battery storage developer. And by the way, we just sanctioned the first 100 MW battery storage project developed by Kyon. This complements our leading position in offshore wind in that country, as well as the acquisition of Quadra Energy, our renewable energy aggregator, with a 9 GW pipeline of aggregation, of aggregation of, to, to commercialize. So we are clearly, I would say, this, first half in a strong execution mode of the strategy, so don't expect any change. We are, and there is, of course, still more to come. In particular, we have also announced recently that we made some important steps towards the FID of our Suriname Block 58 projects by the end of the year, which is, of course, a key milestone for us, our partners in Suriname. As a reminder, this is an operated 200,000 barrels per day oil development with more than 700 million barrels of estimated recoverable oil. We have achieved, as I said, key steps, including the agreements on the field development area with the authorities, but also securing the order for the FPSO, the FPSO, to be able to sanction the projects and should be, I would say, end of the third quarter, beginning of the fourth quarter. I'll wrap up my introduction by just saying that our balanced strategy is so clearly in motion, that we are pushing on all fronts. We are making progress, delivering and executing our plan, which will allow us to reach our ambitious targets this year and delivering top-tier performance, but also preparing the future of the company. So we position the company to be, to lead the pack, and we are determined to deliver to our shareholders of premium returns. And that's the program that I propose you, to show you at our next Investor Day, which will, this year, will be, in New York on October 2. You put that, can put that date in your calendar. And so I look forward to meeting you there, but in the meantime, Jean-Pierre will give you all the details of the second quarter results, and I will be happy to answer to your question today, together with Jean-Pierre. Thank you, Patrick. Let's move to the financials. The crude market remained supportive in the second quarter. Brent slightly increasing by 2% quarter-over-quarter to average $85 per barrel, while the company average LNG price decreased by 3%. In refining, margins continue to normalize with our European refining margin market down 37% quarter-to-quarter. In this context, TotalEnergies reported second quarter 2024 adjusted net income of $4.7 billion, with the first half 2024 totaling close to $10 billion. The company generated $7.8 billion cash flow during the second quarter of 2024, and close to $16 billion for the first half of the year. Importantly, profitability remains robust, with ROACE return on capital, average capital employed of close to 16% at close to 17% at 16.6%. And we maintain strong CapEx discipline and reiterate 2024 net investment guidance of $17 billion-$18 billion for the year. But last but not least, we continue to build on our strong track record of attracting of attractive shareholder distribution, with $2 billion of buybacks executed during the second quarter and up to $2 billion of buybacks authorized for the third quarter of 2024. Also, the board has maintained the second interim dividend at EUR 0.79 per share, which is nearly a 7% increase year-over-year and is 20% higher compared to pre-COVID levels. First half 2024 shareholder payout stands at 45% of CFFO. Moving to the business segment, starting with hydrocarbons. So production was 2.44 million barrels oil equivalent per day in the second quarter of 2024, close to the high end of the guidance range. We continue to see good performance from project startups and ramp-ups, including Mero 2 in Brazil, Akpo West in Nigeria, Block 10 in Oman, Absheron in Azerbaijan, and multiple projects in North. Looking forward, production for the third quarter of 2024 is expected to be stable between $2.4 million -$2.49 million barrels oil equivalent per day, with the expected startup of the Anchor project in the U.S. Gulf of Mexico in the third quarter. Exploration and production continues to perform well. We've reported adjusted net operating income of $2.7 billion and cash flow of $4.4 billion. The company maintained its cost leadership with upstream OpEx per barrel below $5 per barrel during the second quarter. In the integrated LNG business, we continue to increase our structural resiliency by advancing commercialization of LNG through new medium-term Brent-linked contracts with Asian buyers, having recently signed two contracts for a total of 1.3 million tons per year. Turning to the results now, hydrocarbon production for LNG increased 1% quarter-over-quarter, which includes entry into the Dorado upstream gas field in the Eagle Ford basin in the United States, and we progress on our objective to increase upstream integration in the U.S. to further improve resiliency. LNG sales decreased by 18% quarter-over-quarter, notably due to lower spot purchases in a context of lower LNG demand in Europe. Integrated LNG adjusted net operating income and cash flow were both $1.2 billion in the second quarter. The results reflect a lower average LNG price and lower sales, as well as the impact of gas trading not fully benefiting in the continued low volatility environment. LNG trading continues to perform well. Given the evolution of oil and gas prices in the recent months and the lag effect on price formula, we anticipate that our average LNG selling price should be around $10 per million BTU in the first quarter of 2024, which is higher compared to the second quarter. Moving now to integrated power. As mentioned by Patrick, we recently enhanced our asset integration with several flexible capacity additions. Integrated power, once again, delivered profitable growth, with first half 2024 adjusted net operating income of $1.1 billion, up 36% compared to the first half of 2023, due to activity growth. First half 2024 cash flow totaled $1.3 billion, which is in line with the annual guidance of more than $2.5 billion. In addition, return of capital employed for the twelve months ending June thirteenth increased to above 10%. In downstream, refining and chemicals reported $640 million of adjusted net operating income and $1.9 billion of cash flow during the second quarter. Results reflect the sharp decrease in global refining margins since the end of the first quarter, which remain impacted by low diesel demand in Europe and market normalization following the disruption in Russian supply. The company's utilization rates improved to 84.5% from 79% in the first quarter of 2024, mainly due to lower planned maintenance, which partially compensated the decrease in refining margins. For the third quarter of 2024, we anticipate that the refining utilization rates will benefit from the restart of the Donges refinery in France and will average above 85%. Marketing and services benefited from the lower refining margins environments in the second quarter, with adjusted net operating income increasing to $380 million and cash flow increased by 38%, sequentially to $660 million. At the company level, we have been, as usual, active in M&A on both sides, with $1.9 billion of divestments and $1.6 billion of acquisition over the first half of 2024. Our net investment stands at $8.2 billion at midyear, and we confirm our 2024 net investment guidance of $17 billion-$18 billion. During the second quarter, we reported a $1.2 billion working cap release, and we anticipate that the working cap builds reported during the first quarter will continue to reverse over the coming quarters. Debt was stable quarter-to-quarter and improved by nearly 1% year-on-year at 10.2% at the end of the second quarter of 2024. As a reminder, we continue to anticipate structural gearing of around 7%-8%, all else being equal. During the quarter, TotalEnergies successfully issued senior bonds on the U.S. market, totaling $4.25 billion, using conventional formats and privileging long maturity. The average maturity of this issuance was indeed 27 years. Indeed, the board of directors decided to retain flexibility on the format of the bond issuance and to give priority to long maturity. Lastly, I'm pleased to announce that after the capital increase reserved for employees earlier this year, employee ownership in the company is now more than 8%. We also have strong support from our shareholders, who supported all resolutions submitted to the vote at the recent annual general meeting. I will stop here and let the floor for the Q&A. Thank you. Thank you. Ladies and gentlemen, we will now begin the question and answer session. As a reminder, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking a question. If you wish to cancel your request, please press star two. Once again, please press star one if you wish to ask a question. The first question is from Lydia Rainforth of Barclays. Please go ahead. Thank you, and good afternoon. Two questions, if I could. The first one, Patrick, I think you... It's obviously a 100-year anniversary for Total, and I know that you've kind of been very good at giving shares to the employees and things like that. Would you consider a special dividend for a 100 years to, to, to celebrate for Total? And then the second one, actually, if I could just do more macro stuff at the moment, clearly, 'cause there's a lot of moving parts as to the cash flows towards the end of the year. Can you just walk us through both where refining is and where you see that going? And then also on LNG, just where you're signing some of the slopes on the contracts. Thank you. Okay. Good question, Lydia. Maybe I should give to you a special gift of one other share to ask the question, but I'm afraid that today we get, we are not, as we already set up in our cash flow location, the privilege is dividend and buyback more than special dividend. We don't consider today. We are in an exceptional environment as the one which we benefited in 2022. So it was exceptional. We are not there. It's a good environment, but not exceptional. So I would say, sorry to disappoint you, but I'm afraid we prefer to continue to maintain, to increase the dividend year after year and to have a good buyback program. Second, where do we go, refining? Refining, I think, it's clear that I think there is a form of, it benefited during the last two years of some imbalances in the market created by, you know, the Russian flows, which were distracted from Europe, from the U.S., from the normal flows. We have the feeling that now, in fact, the market has more or less restabilizing in this sort of normalization mode from this perspective, even if we can observe that the U.S. are more and more trading against all this gray fleet of Russian oil. So it could have, again, some influence, you know. So that's one part. The other part is that, the demand was not too, was lower this year than the last two years, in fact, so, the inventories are not so exceptional, in fact. I expect that with the driving season during summertime, generally, there is more demand, so we could see, I would say, better margin. If it's today, it's quite low, and in fact, when I say quite low, in fact, it's back to what it was normal before all these exceptional years. So I think our refiners know they have to come back to reality and to deliver good results with lower margins. But again, it's part, at the same time, it's true that we benefit from a good oil price, in fact, $84-$85 per barrel is good. And so you have, you come back to a traditional integration between, I would say, when the price of oil is low, the margins in the refining are lower. Generally, when it's the case, the marketing is benefiting of it, by the way, we've seen that you know, during the last quarter. So I'm not, I would say, I, I think we are more going in a normalization of refining margins. And, you know, when we make our long-term plan, we are more on $35-$40 per ton than $70 or $80 per ton. So maybe because I was in charge of the of this segment, I know that what is the hard, hard reality from time to time. But again, this is typically the type of business which is you need to have your machine, your refineries running when the margin is good, and then you make the cash in, and then you need to be resilient when the margin is more normal. On the LNG, I would say, again, on the LNG, you know, we negotiate quite a lot of new LNG contracts, because all the strategy of the company is to buy and re-up and to sell Brent, in fact, so we are in the middle of that. It's difficult to answer to you because there is a lot of discussions around the world. I would say it's more commercial secret. So, but again, the transformation of area to, to Brent is good for the cash flow of the company, including in a, in a market which we can think that by the end of the decade, it will be a softer market. So this is all the strategy of the company. Brilliant. Thank you very much. The next question is from Doug Leggate of Wolfe Research. Please go ahead. Thank you. Good morning, good afternoon, everyone. Thanks for having me on. Patrick and Jean-Pierre, I wonder if I could ask you about your Suriname progress. My understanding is that when you laid out the strategy last year, Suriname did not have a meaningful contribution to your 2028 cash flow. But now you have an SBM Fast4Ward hull, and obviously, things look like they're moving a little quicker. It seems to me that Suriname could be a meaningful step up in your cash flow in 2028, full calendar year at current oil prices, probably around $4 billion. Can you give us some color as to what you think the progress is? That's true, but in fact, we have decided, as I said last year, that Suriname, we try to execute it in a quick mode, I would say, moving from the end of the appraisal by September last year to the FID. My objective is one year from appraisal to FID. All the teams are being mobilized, by the way, we are using innovative approach, including using the design of a good operator, which is developing projects next to Suriname, which they have a good design. So trying to build on this, FSO, in fact, taking the design, which is design of Guyana, in fact, to apply it, and it's quite efficient. So we move forward quickly. And so that means that the first sort of Suriname is targeted by, I would say, somewhere in mid-2028 or beginning Q1 2028. So it could be quite significant. You know, to be clear, the cash flow from Suriname, as you know, will be big, yeah, because we have, in fact, financing almost all of it. So we'll benefit from the cash flows in a very large way. So the contribution of Suriname, not only to 2028, but 2029, 2030, 2031, 2032, will be important. That's why I'm insisting. By the way, I can tell you that in September, we will extend our guidance up to 2030, because with the rich portfolio we have, we can extend it. Suriname, of course, will be part of the new, 'cause a good color will give to our perspectives by 2030. That is very helpful. Could I ask a quick follow-up on a separate topic in the U.S.? After your Lewis Energy acquisition, are you now comfortable that you have enough hedged gas exposure for your LNG, or do you still intend to do further acquisitions- No ... in the lower 48? No, we don't have enough. We are clear, you know, can make the math. We will, we will, offtake something like, almost, we have, 10 million tons. We have five in Rio Grande, so we need to increase. And by the way, I can tell you that we are working on another deal, so it will be step-by-step deals. It's not a big one, but, we are working on another one, and, we should have news as well for you by, and we'll give more color to you by, September as well. I think an important topic on which, for me is important is to, to show you how we, in fact, all with LNG position, on one part, on the upstream, but on the other side, on the downstream, will be resilient and whatever the price environment will be. I think it's very important, to demonstrate it, and we are acting on it. And on the upstream, there will be more to come, for sure. Thank you so much, guys. The next question is from Irene Himona of Bernstein. Please go ahead. Thank you. Good afternoon. My first question is on marketing. In the second quarter, NOPAT declined about 16% year-on-year for a 2% lower sales volume. How should we think around the impact of your disposal to Couche-Tard versus underlying performance? So what happened if we exclude the sold assets? My second question, Patrick, French politics has been quite volatile recently, and sovereign states can do a lot of things, impose windfall taxes, even golden shares. So I wanted to ask, is there something in particular that concerns you in terms of a potential action by the French state that might be against the company's interests? Thank you. First question is quite easy. In fact, it was more or less $20 million per month, so for a quarter is $60 million, the impact of Couche-Tard, the assets in Germany and Netherlands and half of Belgium. So you can make the math, and in fact, we managed, in terms of cash flow, more or less to we are okay. It's cash flow or it's net results $20 million with see net results, sorry, not cash flow, net results, so $20 million per month. So you can find that you are, it would be reduced to 3%, so it's in line, in fact. So globally, the marketing as a is be as a, I would say, a very performance equivalent to the one of last year, if you deduct this Couche-Tard impact. Okay, first point. Thank you. On the second one, honestly, the French politics, I think, first I would say that TotalEnergies is more stable, which is good, or is a stable company. No, honestly, I think there is a lot of noise around all that. On the golden share, by the way, as to be very clear, on it, there was a judgment which was in 2002 by the European Court of Justice, which has obliged the French government, which previously had the golden share in TotalEnergies equity, to cancel it because it was against the fundamental principle of free move of capital within the European Union. So it has been already judged, so I know that some politicians are speaking to thinking against about it. By the way, with the present law in France, just to clarify with you, it would require at least the French state to invest 5% of shares in TotalEnergies. I understand that they have more, better use of their money than investing billions in the company. That's politics, but again, I'm, I, this is not the point. I think, as I told you before already, you could see ideas like the one in the U.S., by the way, which is taxation on the buyback. You know, the French politicians have all read that, something is happening there, so sometimes it's a little difficult to argue for us against, even if we have done it. But again, we will engage with whoever the new government is, and that's, I think, again, I don't think you should consider it will fundamentally affect the interest of TotalEnergies. Thank you, Patrick. The next question is from Biraj Borkhataria of RBC. Please go ahead. Hi, thanks for taking my questions. My first one was on the deal you did with OMV in Malaysia. I noticed you listed that in the upstream bullets rather than integrated gas. But in the press release, you mentioned the deal would be an anchor for future growth in the country. Just wondering if there's any potential here to integrate yourselves into the LNG facility and whether that's being discussed, and if not, could you just talk a bit about you know, your growth plans there and the strategic rationale for that deal if you can't integrate into LNG? And then the second question is just again on projects and on LNG. So Mozambique, there was an article recently around potential cost escalations. Could you just give us an update on, you know, where we are and expected budget and where, what the next steps are from here? Thank you. Okay. On Malaysia, no, I think, maybe, it will be, fundamentally, the gas revenues from the license in Malaysia is a LNG netback, just to be clear. So for me, it's integrated to the LNG value chain, just to be clear, even if we don't have a... So it's a way that the price, gas price is settled. So first clarification. So the idea, of course, is to continue beyond it, to have access to, and we are already in discussions with some other actors, players, including, by the way, Petronas, to beyond. And they just started, by the way, the Jerun gas field, which just started, this week, last week. So it's a quite a large field, it's producing 600 million scf per day, I think, so we will have a nice share of it. And so beyond it, there is more opportunities to develop, and so we have some plans. And of course, at the end, the more we can link that to the LNG world and to LNG pricing, this is the objective of the company, so we'll work on it. On the Mozambique, I can tell you that everything has been settled with the contractors, so we are clear. We know where we are. In fact, it was more a matter, to be honest, of the cost of the, I would say, frozen period, which was to be absorbed and discussed, because since 2020 to 2024, we have frozen some works. We have some equipments which were, I would say, kept in different locations. So all that has been discussed, all that is settled with them. And so we are on the way to move forward, and we will, as soon as we can update you, we will do it. But the progress have been done in many direction, including on security. Now, we try to regroup all the financial finances around the project. So, and as you know as well, there are some presidential elections in Mozambique coming soon. And so of course, for us, it's important to have the confirmation that the new president will follow the same policy regarding these large projects. And so that's where we are. So say, by end of the year, we should clarify all that. We should be able to move forward. Okay, thank you. The next question is from Martijn Rats of Morgan Stanley. Please go ahead. Yeah. Hi, hello. I have two, if I may. My attention was drawn to the comments in the outlook statement, where you talked about European gas prices in the range of $8-$10 per MMBtu for the third quarter. And that struck me as a somewhat of unusual comment, because I don't know Total to comment all that often on near-term commodity prices. So from that perspective, it stood out, but it also stood out because it seems quite low. TTF is a little bit more than $10 per MMBtu at the moment. So I was wondering if you could elaborate a bit on that expectation, and broadly where it comes from and the drivers behind it. And then the second thing I wanted to ask is on the previous earnings call, we talked a lot, of course, about the potential to either move the listing to the U.S. or maybe not for the full headquarters, but at least to move the main listing to the U.S., and a quarter has passed, and I was wondering if you have an update on those thoughts. Okay. Sorry to, to surprise you. Sometimes you tell me that we are a boring company, so today we try to make it. Honestly, there is no, we've seen when we made a statement, beginning of the year at $8, we moved up to $10, $10.5. So to give you a range of $8-$10 in summertime, there is nothing extraordinary, because it's not the best season. The third quarter is not the peak of the demand, generally. And so as the, as you know, the inventories, storages in Europe are quite, well, full, we don't anticipate a big rebound unless there is an event. So that, I think, giving you this guidance is more reflecting what happens since the beginning of the year, so it's a way to tell you. But again, when you say it's low, $8 is quite high compared to what we were experiencing before 2021. It was more, we had years at around $4-$6 per MMBtu. So $8 for European gas price, even today, it's $10.3 yesterday evening, is a good price for, not only for us, including for all Norwegian operations and U.K. operations. So I would say, it's good for... It's okay. It's lower than what you were, we had in 2022 and 2023, but we made no miracle on that. But still, demand, there's been a landing, and unless the weather will come against cold next winter, we don't anticipate any point. Having said that, we could have other disruptions coming from other parts of the world. Because the main driver today will be, if there is any tension in the energy supply, because a plant could have a problem somewhere in the world, then this market is very volatile, because we don't have much margins between the supply and the demand on the energy. So, sorry to have surprised you, Martijn. On the U.S. listing, no, I mean, it's not... I clarified that in a French newspaper. Maybe it was in French, so we should translate it and distribute it to everybody, which I will ask Renaud and his team to do, because we clarify what we want to do. What we want to do is fundamentally to transform the ADRs in shares, in ordinary shares. That's all. That means at the end, and we want these shares to be cross-listed, I would say, if you want, between Paris and New York. That's fundamentally what we'd like to do. There is nothing else. So transforming the ADRs in shares. The ADRs, we made a test, we had questions with a quiz or questions to almost 40 long-term investors in the U.S. They see some positive, nothing negative, because some investors do not like the complexity of the ADRs, in terms of back-office, in terms of managing it. Some investors could prefer to invest directly on the New York market and not going to the European market, Paris or London or Brussels, so that we do. So we are more in a technical move. We progress, just to tell you, we progress positively, until now, and Jean-Pierre and his teams will work on it. We will update you probably end of September. But technically, there is some technical matters between the different, depository, in fact, firms between Europe on one side, DTCC on the other side. And so we made progress, and we'll be able to have a scheme. So it's fundamentally transforming the ADRs in shares, and so having, giving more liquidity to the shares, which the shares could be, in fact, acquired either in Paris or on the New York market. That's what we want to do. It will add the liquidity, and so we help. It will help attracting more U.S. investors. And as you know, today, we have a larger, a stronger flow of U.S. buyers than on the European side. That's what we want to do. Wonderful. That's crystal clear. The next question is from Michele Della Vigna of Goldman Sachs. Please go ahead. Thank you very much for the time. I've seen that you've been very active in adding more low-cost LNG supply to your portfolio in the last few months with Ruwais, with Marsa LNG. I'm wondering, you must be marketing these volumes to customers at the moment. How do you find the demand appetite for more LNG? And are you comfortable to add more spot volumes to your portfolio, especially if the market starts to become more supplied in 2026, 2027? Thank you. Yeah, good question. Thank you, Michele. Clearly, we have been successful in the last months, and the answer to a previous question, our work strategy is to be able, in fact, to transform some gas, I would say gas volumes into LNG volumes. And so we are active on the Asian markets. We have already announced 2 million tons of new LNG contracts since the beginning of the year to different, and there will be more to come. So you will see, I can tell you more deals to be announced in the next months. We are quite active. As I said, to, as I said, you know, look, we have more or less 10 million tons today of US LNG, which is linked to Henry Hub. We sell part of it on the Henry Hub formula, and we want the rest to be sold on a Brent formula, in fact. The Brent formula, and the answer to your first question, there is an appetite today from Asian buyers, and still at a good percentage. We don't, we don't, I would say, discount our LNG, you know. Why? Because I think the lesson of these Asian buyers is that they have been afraid about what happened in 2022, 2023. Even if they could anticipate that there would be a softening on the market by 2027, 2030, they think for them it's better to hedge part of their own, I would say, purchase, linked to the Brent. In fact, I think today there is more confidence in the buyers' side on the Brent and the stability of the oil market than on the LNG, JKM index, which is, by the way, don't have the same depth as the TTF. So I think this is why you have some appetite on different countries. There are more countries buying LNG, in fact, not only China, Japan and Korea, Taiwan, Vietnam, India. India is, has grown appetite. So, so adding more spot, we have added already. You know, we have added, with Rio Grande, we took 5 million tons. Marsa is, is more, it's 1 million tons, so... But this is the one where we want also to develop a local barging, barging, I would say, market within the Gulf, with a specific market. Yes, we are comfortable, but I think, I would give you—I would tell you, Michele, what the objective we'll have at the end of September is to show you exactly what you said. How do we manage this potentially softening of the market from 2027 to 2030? What is the remaining exposure for TotalEnergies? And you will realize that downstream, in fact, fundamentally, we will transform, and we are transforming our IOC into a Brent. And I think this is good for our, for our shareholders and for the future cash flows of the company. Very clear. Thank you. The next question is from Lucas Herrmann of BNP Paribas. Please go ahead. Oh, thanks very much for your time. Two, if I might. One, the first is just to JP, h ybrids. You've redeemed a portion again this quarter. Can you just remind us what the redemption possibilities are going forward, what the time frames are? And Patrick, apologies, but a general question for you, just on your own thoughts on China and Chinese oil demand development, to look out over the next few years. I guess I've been, it's been a fascination to see the extent to which, you know, gasoline demand is perhaps starting to come under pressure from EV. We've obviously had a fair amount of switching, you know, diesel into gas, LNG trucks, etc, etc. And, you know, demand increasingly feels as though it's coming from the chemical industry and perhaps negating crude. Just your, I mean, just your own thoughts and insights into how you see Chinese oil demand developing next few years. Thank you. Yes. So concerning the hybrids, so you're right. So we decided not to renew EUR 1.5 billion in the second quarter, because we use the flexibility offered by the credit rating agencies. If you can demonstrate that without renewing your hybrids, your credit rating is not affected, so you can use the flexibility. So we see, because we have another EUR 2.5 billion next year, as in the hybrid, in our hybrid portfolio, so we have to discuss with the rating agencies to see what we can do. And so if we can, again, continue to lower our hybrid portfolio. Thank you. Okay. On China, no, having insights on the forecast of the Chinese markets, it's not so easy for, for when you are out. I would say, I think we should not exaggerate as well what happens. I think my view is that the oil market, for the time being, the oil demand globally continue to be driven by China, even if India is part also, is a growing country. I would take the assumption of 0.81% per year is a good assumption, until we will see a real reverse. Does it affect China? I think we are today a little on the western side over. I would say, there's a little of China bashing, I would say, to try to, to try to say that the economy in China is slowing down. My view is that it's continuing to be quite active. And it's true that you have there, some more, the EV sales are impressive, but that was we recently discussing with the CEO of the number five car manufacturer company, and when I asked him his figures, it was still of 20-30%, it's not at 70%. And in fact, it's a little like in Europe, there are EVs, there are also hybrid cars. And so, the hybrid cars are also because the customers, in fact, are looking to the same issues wherever they are in China or in Europe. In fact, they want to have a, we say, a reliable car for most of the time. That's important to keep in mind. So, yes, there is a trend, that's very true. We see some, we see also LNG becoming, for trucks, a new market... but fundamentally, I think for me, it will not affect quickly the oil market. So keeping 1% of demand off per year, I think is reasonable, which is where we are more or less, but well, what we think, what we take into account. Okay. Thanks very much for the comment. The next question is from Alastair Syme of Citigroup. Please go ahead. Thank you. Patrick, just one question. Actually, I just wanted to get your sense on the competitiveness of opportunities in renewables. And, you know, I know there was another German lease bid auction recently that you were one of the two bidders or winning bidders, but it was quite strange. I think, you know, your German partner probably pulled out because they thought the auction had become too expensive. And, you know, I get it, the markets always have a difference of opinion, but can you give us a sense of where that difference lies? Yeah, yeah. Okay. You know, if we made the bid, but if we think it's competitive, otherwise, we don't do it. First comment. Second comment, in fact, when you look and you will understand what we've done in few weeks, we are trying to just, I think one of my colleague in Germany has made it public in a, in an interview. In fact, fundamentally, we think that, this block that we have acquired is just, its license is just next to the one we acquired in the first round. So we want to make synergies of development in order to be more efficient. And so, that's the objective. And this could go, by the way, by the fact that we restructure all the properties we have in offshore wind in Germany. So you will see the story coming, coming year later. So but again, what we think, fundamentally, and the German partner, by the way, is a nice partner, but we have announced yesterday that we went with him in Netherlands. So probably the Netherlands are good and Germany. In fact, he has a different view because he has another past portfolio in Germany, so we are building the portfolio, not exactly the same approach. But if we do it, it's because... And it's linked to the German power market, in fact, because in Germany, you know, German government has decided a policy with no nuclear, exiting coal, so it's fundamentally a renewable and gas market. So the gas, the power price will be driven by the gas, in fact. And when you look to the perspective of the gas price in Europe, you can be optimistic on the electricity price in Germany. So that's part of the link that we want to do, and so that's why we are building today a full integrated power portfolio in Germany. It's not only the offshore wind. And so you should never, and I know, Alastair, it's difficult for me to convince you, but you will see and why we are more profitable than others. You don't— You should not look to the renewable opportunity only. It doesn't work like that. A green intermittent electron has no value or little value. What is good is to have a clean, firm power for customers. That's what we do in Germany. Yes, we need some renewable sources to have the clean part, but we need to combine them with flexible assets, and flexible assets are batteries. TotalEnergies should participate to have a-- We'll find a way to have access to gas-fired power plants in Germany. Otherwise, my speech will not be consistent. And so you can, I can announce you the next steps of what we want to develop. That's why also we bought this aggregator of renewables to give flexibility in trading the system. So the fundamental business model we have is not renewable. Renewable profitability, it is what it is, and you know it. But where you make money is when you combine these green electrons with the flexible assets, gas plants, and you deliver to the customer a clean, firm power, then you increase a lot of value. And the renewable-- So do you allocate this profit, this value, to the renewables or to the gas plants or to the batteries? I don't care. At the end, this is the integrated model, and this is what we deliver to you quarter-after-quarter, and we'll increase it. So that's the business plan. So it's not a matter only of opportunity, of renewable, it's a matter of integration. And that's why today we have a return on capital employed above 10%. The renewable assets alone will not be there. I admit it, but it's not what we are looking to. Okay. Well, I look forward to October, and in the meantime, enjoy the Olympics. You need to listen to me a little bit. Okay. The next question is from Christopher Kuplent of Bank of America. Please go ahead. Thank you very much. Let's see whether I've listened enough, Patrick. I'm sure. Can I come back to the topic of green hydrogen and that deal that you've announced with RWE? Can you comment a little bit about the competitiveness of the industry? You were instrumental in trying to create a clean hydrogen market, and it seems that deal in the Netherlands suggests you feel you're better off creating the value chain yourself rather than buying it at currently available prices. So be interested to see what you feel you can give to us here. And if I may go back to the U.S. and ask you a little bit around the idea of M&A and how attractive or not you feel your current-... Acquisition currency is if it's not cash, in terms of being able to do deals, is that one element declining, let's say, improving currency that you have in New York? And if I can sneak in a third question, you know, I would expect net debt to fall as the net working capital position drops into year-end. How much room do you give yourself to surprise us what more than 40% CFFO means in terms of shareholder distributions? Thank you. On the last question, I think you have the answer in the speech of Jean-Pierre. Jean-Pierre told you that we are confident we could come back to a gearing of 7%-8%. So that's, and it's part of the working capital build during the first quarter, which will be released along the year. More than 40%, more than 40%, I confirm more than 40%. That's, as we, I think you have the figure for this quarter, whether it's 40, 45%, more than 40%, 45 today. So it's, the guidance will not be, will not be changed. But the delivery will be real. That's, you will see it. First question, so again, no, I think you are, it's more, it's more complex than that. We have different ways to provide green hydrogen to refineries, which again, because of the RFNBO regulation in Europe, creates an economic, an economic scope, to, to make, to make an added value, because you avoid the ETS on one side, and you create an additional new product, and this new product, according to the RFNBO regulation in Europe, has a added value. The question is how much do you pay for the hydrogen, obviously, green hydrogen? In fact, we are looking to both ways. Either we, there are different ways, by the way. In Normandy, in France, we have made a tolling of green electrons. It was a tolling agreement with Air Liquide. We toll green electrons. We don't invest in the, electrolyzer. They run it, and we toll it, so we have a tolling fee, and we will get the green hydrogen outside for out of the electrolyzer. That's the tolling one. We could have, as we explained, by the way, yesterday, we have again, just made a deal with RWE to share, to invest offshore wind and asset, and to get 50% of the electrons in order to transform them into electrolyzers. It could be, it will be a local electrolyzer, either through tolling or we are looking to maybe part of it could be invest, invest by ourselves in order to, to compare the different, because it's a, it's an infant industry. So we want to invest and compare the different ways between tolling, investing, and that's where these electrons will go. And then you have a third route, which is to just purchase green electrons from abroad. Then it's a question purely of competition, market, and being the first mover, we announced a deal with Air Products. Being the first mover from this perspective, I think gives us access to a good price. And so when one day, today, it's premature because all these discussions are moving on, but when we compare the different routes, and again, it's more or less equivalent, of course, the question of when you import, it's the question of competitiveness of your supplier, and they will take far more risk, probably, because we are taking, but that's part of the discussion we have with some suppliers. So what I can tell you, at the end, all the deals we will sign will allow us to create value, not only to avoid the ETS, but on the top of it, to capture part of the added value of these RFNBO products, which are the results of the European regulations. And again, this match well with this RFNBO framework, you know, which is a sort of a regulated economy, which creates a bubble where you can develop some green hydrogen. I don't tell you from my demonstration that green hydrogen is cheap, but it, you can create an economic framework and some value for, for refineries, and at least reducing the emissions and avoiding to pay these ETS. That's where we think about it. No, U.S. M&A, you are too smart. No, no, we just want to, we want to improve the value of the shares for you. So it's obviously not to make M&A directly. No, no, that's not the point. Again, as you know, we have a, we have a, a large and rich portfolio of projects. Why should we like, would like to make more M&A with shares? So it's not the main driver. The main driver is fundamentally, as I answered previously, to transform the ADRs in shares, because it could be attractive to some U.S. Investors to invest directly in New York, in our shares, and, it's just giving more liquidity, and if it's more attractive, it could help, we could think that it could help, not, I think, to fill the famous gap, but part of it. So that's contribution to, I would say, the TSR of the company, which is already one of the best of the, if not the best, is a number one or two, or one, I think, since December 2023, December 2024. So it's improving the TSR of TotalEnergies to be more attractive. That's the objective, fundamentally, of this move. Thanks very much, Patrick. Thank you. The next question is from Matt Lofting of J.P. Morgan. Please go ahead. Hi. Thanks for taking the questions. Two, please, if I could. First, just coming back to the longer-term growth proposition of the company, I think you highlighted earlier some of the strides that you've made during the first half of the year in advancing projects and strategic execution. If you think about it in the context of oil and gas growth, 2%, 2%-3% CAGR to 2028, or the 4% energy production growth to 2030, how significant has the de-risking of those objectives been through the last six to nine months, and what are sort of key projects apart from Suriname outstanding for the second half of the year? And then secondly, I wanted to just come back on gas and LNG. I think in the press release this morning, you called out sort of strength around sort of China and India from a demand perspective. Just to what degree does TotalEnergies see that strength as seasonal versus structural? Thank you. Okay. On the first one, thank you for the question first. Now, I think, again, we we set this objective for next five years in September 2023, to 2%-3%. We knew and we were very clear about the number of projects we had to sanction, and I think we've done a lot. I think most of the work has been done during the first six months. It's important because it's for us, it's clear that it's a way to capture quickly the costs and not to see more inflation coming tomorrow. So it was a key priority. So we have the two projects in Brazil, the one in Angola, Suriname will come soon again. So I would say, and you add also part—I could add that on Iraq, we are also progressing, but the other one on which we progress quickly to go to the first phase of Iraq. So that's for the oil. On the LNG, we postponed PNG, Papua LNG, because it was too expensive, so not the volume driven. But we had the opportunity to sanction Marsa LNG to rebound, but we just joined the Ruwais LNG projects for 10%. So all that being led, so we have multiple options in the portfolio, and so I'm very confident to deliver this cash flow, but I'm even more confident in July 2024 than September 2023, because most of the work of sanction has been done, and so it's progressing. Again, I think in September, in October, October 2, I say September, it's October 2 in New York, of course, it will be part of the presentation to update you on the progress to this objective of 2%-3%, and even, again, to speak to you about up to 2030, because we have a portfolio which is rich, and so we are confident about the growth we can deliver by this, by this timeline. So, that's the point. So Suriname is a big one. Honestly, I think we are, is the main one, which will come in, in 2024, I think, in my... And, yeah, no, Iraq Phase I, the, going to 110,000 barrel per day, which is progressing very quickly as well. And by the way, very well. So the teams are doing an excellent job there in Iraq. On the LNG India, China strength, it is... No, I think you see something more fundamental in India. The investment, you see, an industry demand in India, in fact, coming. The Indian government has really, I would say, invested in some gas infrastructure around the country, and you have more and more industries, not only refineries, but others who are going to come to LNG and to gas. And I think it's a trend, even surprisingly, at higher price than before 2021. You know, in 2021, I think I answered questions, telling you that in India, it's difficult to sell beyond $6-$7 per million BTU. In fact, we continue to develop the business at $9-$10 per million BTU. So I think there is a fundamental structural demand coming from India, and we are convinced that the Indian market will take the relay, I would say, from the traditional Korea, Japan, and even China. On China, probably it's more seasonal today, I think, because there are already a lot of infrastructure. China is moving very quickly on these, renewables, continue to increase its coal production. And again, the gas is more driven by transportation, like it was, mentioned by Lucas, or by industries. So the gas demand, LNG demand in China is not really driven by power today, because the power is mainly coal and renewable. So, so that's- but there are, there are some disc- some decisions. The Chinese recently have again, spoke again about their, equivalent of ETS CO2 market, but today it's quite small and limited, but they want to expand it to all the industries. So these type of drivers, you know, could really have an impact, but we see more of the Chinese market growing thanks to, LNG, industry and transportation more than power, in fact, on the LNG. So honestly, I think, today we have 400 million ton market. It will become 600 million ton market, but this 200, this 50% of demand increase will be absorbed quickly for five years. I think part of it today would already be being absorbed in Southeast Asia if we are not constrained by supply, in fact. Today, we are because I remind you that we took 50 million tons from Asia to Europe, and since 2022, we did not increase really the LNG production. It's quite stable. So this will be easy to grow. So this growth will come, and you have also many more countries open to LNG. We see Vietnam as a terminal, Philippines, we have a terminal. So you are in fact in Southeast Asia, most of the countries will have be able to receive LNG. So then, and if you can think that you will have a good supply, so price will soften, it would even incentivize the demand and accelerate the demand by the end of this decade. So I think, and it's not just seasonal, probably, this is structural. Super. Thanks very much. The next question is from Henri Patricot of UBS. Please go ahead. Yes, everyone, thank you for the update. Two questions, please. Maybe the first one, just coming back on the cost. I was wondering if you can comment on the inflationary pressure that you're seeing, and you mentioned P&G, LNG, where we saw cost and then push project. Is that quite specific, or are you seeing more probably have some inflationary pressure? And then secondly, just a quick question on the CapEx guidance for the year and whether we should expect the cash outflows related to acquisitions to be offset by cash inflows from disposals this year. Thank you. The first question, I know there is nothing to hide. There is an inflation in our industry compared to the low point where we were in 2020. Today, I think we are 20% higher in most of the costs, but at 20% we can manage it, and that's why we can sanction our projects like the ones we have done, even if we can also take some innovative measures like making a junior array, you know, to manage this cost for the future. Having said that, Papua New Guinea probably for specific, because isolated projects in I would say remote areas, not really projects in part, so to be, as we said recent before, we consulted traditional Western we say suppliers, they are not very interested, or they have some limited resource. They think they could deliver more margins for them to make a project in the U.S. than in our, in our, than in Papua. So what we are doing is looking to—we have decided to go to a larger, we say, supplier, other suppliers, in particular Asian ones, Indian, Chinese. So we could have, I think we should be able to come back to, something more CapEx, which would be, reasonable in, in this environment. But again, by the way, another point is that there was an inflation, but today it's more stabilizing, in fact, because for example, in the, in the rig market, in the drilling market, you begin the, the drilling contractors, because are facing also some supply chain equipment, problems, so it does not import. There is still some rigs which are not used, in fact. So it's, so in fact, we don't have, they don't have the full value chain, the full supply chain ready to, to execute all what they would like to do. So yes, there is an inflation, but we manage it, and, and we'll come back on that topic as well in, in beginning of October. The second one, yes, we always gave a guidance of, $17 billion-$18 billion of net CapEx, and this will be, again, as Jean-Pierre told you, I will reiterate this, with guidance. I would say last year, for the five years business plan, we gave you $16 billion-$18 billion, if I remember mind well. I would be surprised that we will not confirm $16 billion-$18 billion on October second. Okay, and CapEx view should be also within that, that range. Okay. Thank you. The next question is from Paul Cheng of Scotiabank. Please go ahead. Hi, good morning. Two questions, please. I think the first one is for Jean-Pierre. In your press release, you said that the integrated power result was impacted by some seasonality, like in Europe, the electricity seasonal demand. Can you help us to understand that? How big is that impact? And maybe, in general, what kind of other visible seasonal pattern we should expect in the integrated power business for you? Second question, I think this is for Patrick. Any update for Venus? Thank you. Main driver behind my comment is in relation with the CCGT that are less used in summer for obvious reason, compared to winter. That's, I should know - Can you quantify how big is that impact? Also, other than that, is there any other seasonal pattern in the other quarters that we should be aware? No, no, we are young in the integrated power, so we don't have an enough long history of results to answer precisely to your question. So we just, we have to explain why 500 is a little lower than the previous quarter. And when we looked at the figures, one of the main explanation was just that, the gas power. The gas power plant level of use in Europe was very low. Yeah. Less than 10%- Yes. - compared to something around 40%. So that's one explanation, which is the first- Yeah. First explanation is this one. Yeah. Okay? Yes. Namibia, I mean, on Venus, just to tell you, I know, we have again finished the appraisal of Venus, so now we have, we have some reserves. We are now working on the development scheme. As you know, we have been quite clear with you, it's positive. We have a lot of oil, but there is also some gas. So the question will be: Can we find a way to develop this, oil pool, managing the gas, and I would say, reinjection in an economic, way? Because, of course, all that in the end needs to fit with our criteria of, break even less than $30 per barrel, of course, less than $20. Our engineers are working on it. It's a little more complex to develop business than-... create value in Suriname, to be clear, because there is, the gas quantity to manage is larger. But I think we have a key, it's a clear objective to the teams to deliver some value. And so we'll update you today. The agenda is again by end of twenty- we are in mid 2024, by end of 2025, to have a clarity probably before to say what, where we are with this development. So we are working on it. Patrick, that, we know there's a lot of gas, as you mentioned, but other than that, is the geological structure, is compact or that is more than straightforward, let's say, comparing to Suriname or Guyana? Well, on Venus, I would say, I know the comments of one of my peers who say there is a lot of heterogeneity, difficult to find the oil pool. We have the oil pool. Of course, is we have a core of the pool, which is a better quality, like always in all the fields that I know since I'm in this industry. And then you have the flanks of the pool, which are degraded quality, which is always like that. But I think we have the pool. The question is more, again, the capacity management of the, of the... So we have a pool of oil, which is big enough to make a development. The question is to manage with acceptable cost, all the gas, which will come with the oil, and to be able to reinject it in good conditions. Knowing that we are, I remind you, about 3,000-meter water depth, so it's not—it's another, it's part of the challenge, you know, and the deeper it is, the more expensive it will be. So that's, that is the link. So that's more, now, today, for me, it's a question of commercially, finding a way to make it profitable as per our criteria. And but I think I, I think I'm always optimistic, but I'm optimistic. So we have the right oil pool. Very good. Thank you. The next question is from Bertrand Hodee.[Foreign language]. Sorry, Hodee of Kepler Cheuvreux. Please go ahead. Thanks for taking my question, too. If I may first on Suriname, can you confirm, and I suggest suppose your earlier comment points to an FID for 2024? But can you, do you believe you can achieve still the $9 billion budget you've earlier penciled last year? And the second question is on LNG. You've signed a 2 million ton long-term contract to Asian customers, but you have take a lot of the commitment in the last, let's say, 15 months into being Rio Grande for 5 billion ton, QAC, Q FS, and now, who else? Do you have a target in terms of volumes you would like to secure on a long-term basis for Asian customers? Okay. On the Suriname part, we are in the process to make the FID, so I don't have today the figure. What I can tell you is at the end, this development will be sanctioned because the cost, CapEx plus OpEx, will be lower than $20 per barrel. That's a strict criteria. We are committed to it, so we'll meet that target. This is... And if I say you that, it's because I'm optimistic that we will reach it. So that's the point. Secondly, on the LNG, okay, you know, I described what we want to do. Fundamentally, we have some Henry Hub exposure. Part of it, we can resell it as Henry Hub. In particular, we have a good exposure, we have a good customer in South America, and they buy on Henry Hub basis. So this part, Henry Hub to Henry Hub, is fine for me. And then the rest of the Henry Hub, the objective is to be able to secure as much as we can on the Brent basis and a medium, long-term, medium-long term basis. We want to transform Henry Hub in Brent. So if we reach 100%, perfect. If we reach 80%, 80% is a minimum we want to reach of this conversion, just to be clear. Because as we analyze, the market will soften by the end of the decade, we want to protect the company. It's not necessarily 15, 20 years, you know, it's a question, we could have also so five, seven years contract, which will help us to swallow a softer market and then to rebound. So that's more, that's the idea, fundamentally. And it's true that what is behind is that my view and our view is that the oil market, because of our peak position, is probably more stable than the gas market from this perspective on medium, long term. So we are more bullish on the oil and on the Brent, and I would say on some volatility we could have in this LNG market. Very clear. Thank you. We like the oil. The next question is from Jean-Luc Romain of CIC Market Solutions. Please go ahead. Thank you for taking my question. You have built an interesting value chain in integrated power in Texas, and in the last quarter, there have been very big volatility and some very warm days. I was wondering how you can capture those? And the second question was, you explained us your utilization rate for the European natural gas power plants was very low. How was it in the U.S.? No, I think, on the contrary, you know, we know that the gas-fired power plant that we have acquired most of their use is when they need the air conditioning. It's, it's the cooling, it's heat wave. And the heat wave today in the U.S. has been very strong in the last month, and so I think the results of the first quarter will be even better. So I can tell you these gas plants are used at a very high rate today, so it was an excellent acquisitions. And by the way, they are used, as they are driving the price at a point where the price of electricity is quite good. So that's really, I think the demonstration. And of course, we have some, our solar plants, we have some batteries, and also we can benefit with the batteries in the integration. So, you will see the positive impact of these, I would say, flexible assets, I think even more in the third quarter. Because the second quarter, I think we closed the deal, we don't have a full quarter yet. And by the way, the heat wave did not come in March-April, but a little later in June, July, etc. So that's clear, but it was clear in the model that when we study this acquisition, that the summertime was the best part of the year. Which, by the way, is counter. Compared to the wintertime in Europe, is very sort of counter, the counter-seasonal effect between, the Texas and Europe from this gas-fired power plant point of view. Thank you very much. The last question is from Jason Gabelman of TD Cowen. Please go ahead. Hey, thanks for squeezing me in. I wanted to ask two questions. The first one is on the gearing level. It was stable quarter-over-quarter, and I know you discussed an expectation it's gonna decline. But I'm wondering if it stays at this level for longer, or is there a level that it increases to, that impacts the decisions around the distributions that you're paying out, specifically the buyback pace? And then my other question is just on the quarter, we saw upstream OpEx move a few hundred million dollars higher quarter-over-quarter, despite production being relatively flat. Was wondering what drove that, if that's structural or if that's a reverse next quarter? Thanks. The OpEx of E&P, we are lower than $5 per barrel, and I think, I will come back to you, I think. On the gearing, no, honestly, 10%, 8%, it has no impact on the decision on the buyback. Be clear. So 10% gearing- Yeah. - or 8% gearing, it's not making a difference. The 8% is more linked, again, we had a working capital build, which was quite big. We know there are some fiscal and other matters behind it, so we know that along the years it will come back. So that's why Jean-Pierre told you 8%. Last year it was 6%, but the 5%-6% was really exceptional from a very big working capital release, which is very exceptional. So for me, but again, from the board point of view, we don't make a difference from a buyback and return policy point of view, 8%, 10%, 12%, etc. Yeah. I think we are, the balance sheet is strong enough to maintain that policy. Is there a gearing level? More than 40%, so more than 40% is what is driving us. More than 40%- Is there a gearing? No, there is no gearing in it. Is there a gearing level? Yeah. No. Okay. All right. More than 40% payout, that's the objective. Okay, thanks. Yeah, no, just, I have the answer to your OpEx question more precisely. My teams wrote me on the paper that in fact, it's linked to some seasonal. We have some turnaround, I think, in the U.K. and Denmark. We have some more work programs of so seasonal effects, and obviously generally in the second quarter. That's the reason why. But no, honestly, there is no, don't see inflation. Yeah, we'll be able to deliver less than $5 per barrel on OpEx. Between today and our financial commitment, we'll maintain this OpEx of $5 per barrel until the end of the decade. It's deeply rooted in the portfolio and in the projects in which we invest. Great, thanks. This was the last question. Back to you for any closing remarks you may have. Well, thank you again. I think again, this, this quarter, I think, we have delivered, our roadmap for the year. As I said, I will insist, we have made a lot of progress on our, I would say, on our, our strategy and the execution of our growth, from 2023 to 2028, and we will, and we'll be able to, to demonstrate to you how the portfolio is growing, but also is resilient to the volatility. These are both, it's a fundamental to drive the strategy, resilient to the volatility of NG, of course, etc. And so, again, I wish that we all meet you on October 2nd in New York in the morning, so that we could have some discussions and presentations. So thank you. I wish you all a good holidays, and happy to meet you in New York. Ladies and gentlemen, this concludes the conference call. Thank you for your participation. You may now disconnect.