Good morning or good afternoon, everyone. Patrick Pouyanné speaking. So before Jean-Pierre goes through the second quarter financials, I thought that midyear 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 focused 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 pillars are driving the growth for the company. So during the 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. But I would like to remind everyone of the financial considerations regarding three large FPSOs Kaminho in Angola, Sepia 2, and Atapu 2, which are world-class oil productivity projects with low technical operating costs; the $20 per barrel sanctioning criteria for Angola is under $30 per barrel breakeven. So these are three major oil projects, but we also have sanctions on the LNG side, including 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 Nigeria LNG. So these projects will not only contribute to our objectives to grow our upstream by 2% to 3% per year in the next five years, but they will also boost underlying free cash flow generation and ultimately shareholder distributions. On the second pillar, integrated power, we have reached quite a compelling ROCE above 10% this quarter, and Jean-Pierre will elaborate on this. We have made strong progress towards deploying and completing our integrated power business model by acquiring flexible assets that allow us to extract maximum value from the renewable assets in three key markets: Texas, the UK, and Germany. We closed all CCGT deals in Texas and also announced the acquisition of the CCGT in the UK. Both of these markets have all the building blocks that define our integrated power model: renewables, flexible assets, and end customers to deliver clean firm power, which prices at a premium compared to green intermittent renewable power. We also acquired flexible assets in Germany through our acquisition of Kyon Energy, a leading battery storage developer. By the way, we just sanctioned the first 100-megawatt battery storage project developed by Kyon. This complements our leading position in offshore wind in that country as well as the acquisition of Quadra, our renewable energy aggregator with a 9-gigawatt pipeline. So we are clearly in a strong execution mode of the strategy during this first half. Don’t expect any change – we are making progress delivering and executing our plan, which will allow us to reach our ambitious targets this year and deliver top-tier performance while preparing for the future of the company. We positioned the company to lead the pack, and we are determined to deliver premium returns to our shareholders. This is the program that I propose you to present at our next Investor Day, which will be held in New York on October 2nd. You can put that date in your calendar. I look forward to meeting you there. In the meantime, Jean-Pierre will provide all the details of the second quarter results, and I will be happy to answer your questions today together with Jean-Pierre.

Thank you, Patrick. So let’s move to the financials. The crude market remained supportive in the second quarter with Brent slightly increasing by 2% quarter-to-quarter to average $85 per barrel while the company average LNG price decreased by 3%. Refining margins continue to normalize with our European refining margin down 37% quarter-to-quarter. In this context, TotalEnergies reported second quarter 2024 adjusted net income of $4.7 billion, with the first half of 2024 totaling close to $10 billion. The company generated $7.8 billion of cash flow during the second quarter of 2024 and close to $16 billion for the first half of the year. Importantly, profitability remained robust with ROCE, return on capital employed, averaging close to 17% at 16.6%. We maintained strong CapEx discipline with a 2024 net investment guidance of $17 billion to $18 billion for the year. But last but not least, we continue to build on our strong track record of attractive shareholder distribution with $2 billion buybacks executed during the second quarter and up to $2 billion of buybacks authorized for the third quarter 2024. Also, the board has maintained the second interim dividend at €0.79 per share, which is nearly a 7% increase year-over-year and is 20% higher compared to pre-COVID levels. The first half 2024 shareholder payout stands at 45% of Sepia 2. Moving to the business segments, starting with hydrocarbons. Production was 2.44 million barrels of oil equivalents per day in the second quarter of 2024, close to the high end of our 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 and 2.49 million barrels of oil equivalent per day. We would expect to startup on the anchor project in the U.S. Gulf of Mexico in the third quarter. Exploration and production continues to perform well. We 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 during the second quarter. In integrated LNG, we continue to increase our structural resiliency by advancing commercialization of LNG through new medium-term Brent-linked contracts with urgent 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-to-quarter, which includes entry into the Dorado upstream gas field in the Eagle Ford basin in the United States, and we progress on our objectives 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 the 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 benefiting in the continued low volatility environment. Energy trading continues to perform well. Given the evolution of oil and gas prices in recent months and the lag effect on price formulas, we anticipate that our average LNG selling price should be around $10 per million BTU in the third quarter 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 $1.2 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. Additionally, the return on capital employed for the 12 months ending June 13 increased to above 10%. In Downstream, Refining & 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 remained 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 plant maintenance, which partially compensated for the decrease in refining margins. For the third quarter 2024, we anticipate that the refining utilization rate will benefit from the restart of the Donges refinery in France and will average above 85%. Marketing & Services benefited from the lower refining margins environment in the second quarter, with adjusted net operating income increasing to $380 million and cash flow increasing 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 acquisitions 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 to $18 billion. During the second quarter, we reported a $1.2 billion working capital release, and we anticipate that the working capital builds reported during the first quarter will continue to reverse over the coming quarters. Gearing was stable quarter-to-quarter and improved by nearly 1% year-on-year to 10.2% at the end of the second quarter of 2024. As a reminder, we continue to anticipate structural gearing of around 7% to 8%, all else being equal. During the quarter, TotalEnergies successfully issued senior bonds in the U.S. market, totaling €4.25 billion using conventional formats and privileging lower maturities, the average maturity of this issuance was indeed 27 years. The Board of Directors decided to return flexibility on the format of the bond issuance and to prioritize low maturity. Lastly, I am pleased to announce the success of 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 open for the Q&A. Thank you.

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. 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 said a 100-year anniversary for Total. And I know that you've been very good at giving shares to the employees and things like that. Would you consider a special dividend for 100 years to celebrate Total? And then the second one, actually, if I could just see more macro stuff at the moment, clinics, there are a lot of moving parts to the cash flow towards the end of the year. Can you just walk us through both where we're finding is and where you see that going? And then also on LNG, just where you are signing some of the slopes on the contracts? Thank you.

Okay. Good question, Lydia. Maybe I should give you a special gift of another share to ask your question, but I'm afraid that today, we are not, as we already set up in our cash flow allocation, prioritizing dividends and buybacks over special dividends. We don't consider today, we are in an exceptional environment like the one which we benefited from in 2022. 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 increase the dividend year after year and maintain a good buyback program. Now, regarding Refining, I think it’s clear that it benefited during the last two years from some market imbalances created by disrupted Russian flows to Europe, the U.S., and the normal flows. We feel that now, the market has more or less stabilized into a normalization mode from this perspective. Even if we can observe that the U.S. is chasing against this large fleet of Russian oil, which could have an influence again. So that’s one part. The other is that demand was lower this year than the last two years, in fact. The inventories are not exceptional. I expect that with the driving season during summertime, there will generally be more demand. We could see, I would say, improved margins. Today, it’s quite low. And when I say quite low, it's back to what it was normal before all these exceptional years. Our refiners now have to come back to reality and deliver good results even with lower margins. But again, it is typical of the business; you need your refinery to run when margins are good, and then you make cash when margins normalize. Regarding LNG, I would say, again, on the LNG front, we are negotiating quite a lot of new LNG contracts since our strategy is to buy Henry Hub and sell Brent. So we are in the middle of that. It's difficult to answer because of the many discussions happening globally. I would say it’s more commercial secret. We are transforming Henry Hub to Brent, positively impacting the cash flow of the company, and we anticipate that by the end of the decade, it will be a soft market. This is part of our strategy.

Brilliant. Thanks very much.

The next question is from Doug Leggate of Wolfe Research. Please go ahead.

Thank you. Good morning and 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 SPM fast-forward hull. 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. A full calendar year at current oil price is 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 decided, as I said last year, to execute Suriname quickly, moving from the end of the appraisal by last September to the FID. My objective is one year for appraisals with FID. Our teams are mobilized. By the way, we are using an innovative approach, including using the design of a good operator, which is developing projects next to Suriname, with a good design. We are trying to apply this FPSO design from Guyana efficiently. We are moving forward quickly. First oil for Suriname is targeted for somewhere in mid-2028, beginning Q1, 2028. So it could be quite significant. To be clear, cash flow from Suriname will be substantial because we have financed almost entirely. We will benefit significantly from the cash flows. The contribution of Suriname, not only to 2028 but also to 2029, 2030, 2031, and 2032 will be important, which is why I insist on it. We will extend our guidance up to 2030 because we have a rich portfolio to showcase.

That is very helpful. Can 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 plan to do further acquisitions in the Lower 48?

No, we don't have enough. We can calculate our needs. We will take something like almost 10 million tons; we have 5 million tons in Rio Grande. So we need to increase our position. By the way, I can tell you that we are working on another deal. It won’t be a big one, but we are working on it. There will be updates by September as well. I think it is important to demonstrate how we are managing LNG positions on both the upstream and downstream sides to ensure resilience regardless of the economic environment.

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, nobody declined about 16% year-on-year for a 2% lower sales volume. How should we think about the impact of your disposal of Couche-Tard versus underlying performance? So what happened if we exclude the sold assets? And my second question, Patrick, French politics has been quite volatile recently. 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 potential action by the French state that might be against the company’s interest? Thank you.

The first question is quite easy. In fact, it was more or less $20 million per month. So in the quarter, that's $60 million, the impact of Couche-Tard. The assets in Germany, the Netherlands, and half of Belgium, so you can calculate that. In fact, we managed to cope with cash flow resulting in a net result, so $20 million was a tax result, thanks to synergies. So globally, the marketing performance is equivalent to that of last year after excluding the Couche-Tard impact. The second point regarding French politics: TotalEnergies is a stable company. Honestly, I think there is a lot of noise around this. With the golden share, it was judged in 2002 by the European Court of Justice, which forced the French government to cancel it because it was against a fundamental principle of capital removal within the EU. Some politicians may try to introduce this again, but with the present law in France, it would require the French state to invest 5% of shares in TotalEnergies. I believe they have better use for their money than investing billions in the company. As for taxation on buybacks, French policies have indicated they might consider this, and it can be challenging for us to navigate.

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 OMB in Malaysia. I know that you listed that in the upstream bullets rather than integrated gas. But in the press release, you mentioned the deal will 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. If not, could you just talk a bit about your growth plans there and the strategic rationale for that deal?

Yes. Regarding Malaysia, the gas revenues from the license in Malaysia are LNG netback. So for me, it’s integrated into the LNG value chain. The idea is to continue developing it, and we are already in discussions with some other players, including PETRONAS, about further development. They just started the Jerun gas field. So we’ll have a nice share of it. There are more opportunities to develop. We want to connect as much as possible to the LNG world and pricing; this is the objective. Concerning Mozambique, everything has been settled with the contractors. We are clear about where we stand. There were more costs incurred, but it was manageable. We are also working on security arrangements and trying to regroup finances around this project. We are awaiting confirmation that the new President will follow the same policy regarding these large projects.

Okay. Thank you.

The next question is from Martijn Rats of Morgan Stanley. Please go ahead.

Yes. Hi, hello. I have two, if I may. I was – my attention was drawn to the comments in the outlook statement where you talked about European gas prices in the range of $8 to $10 per MMBtu for the third quarter. And that struck me as somewhat of an unusual comment because I don’t know Total to call that often on near-term commodity prices. So from that perspective, it stood out, but it also took 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. In a quarter that's passed, I was wondering if you have an update on those thoughts.

Okay. Sorry to surprise you. Sometimes you tell me that we are a growing company. Today, when we made a statement at the beginning of the year, at $8, we moved up to $10, $10.5. To give you a range of $8 to $10 in summer, there’s nothing extraordinary because it’s not the best season. The third quarter is not the peak in demand generally, and the inventories in Europe are quite full. We don’t anticipate a big rebound unless there is an event. So I think providing this guidance reflects what's happened since the beginning of the year. But when you say it’s low, it is high compared to pre-2021 levels, where we had years around $4 to $6 per million BTU. $8 is a good price for European gas today. It’s lower than what we experienced in '22 and '23, but adequate. There could be disruptions from other parts of the world affecting prices. Importantly, there are still elements that make these positions stable. So looking to the U.S. listing, no – I clarified that in the French newspaper. I need to ensure that our thoughts are distributed widely. What we want to do is fundamentally transform the ADRs into shares. We want these shares to be cross-listed between Paris and New York. That’s fundamentally what we’d like to achieve. We’ve conducted tests with long-term investors in the U.S., with positive feedback regarding the readiness of the shares to become a more liquid instrument. We hope to attract more U.S. investors.

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 Roubaix and 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 '26, '27? Thank you.

Yes. Good question. Thank you, Michele. We have been successful in the last months. Our strategy is to transform gas volumes into brand volumes. We are active in the Asian markets and have already announced 2 million tons of new LNG contracts since the beginning of the year to various buyers, with more to come. We have about 10 million tons of U.S. LNG linked to Henry Hub. We sell part of it on the Henry Hub formula and want the rest aligned with the brand formula. The response to infrastructure fits the appetite from buyers, who are more confident post-2022, preferring to hedge around brand. More countries are buying LNG today, not just China, Japan, and Korea, but also Taiwan, Vietnam, and India. Given that we have already added to our positions with Rio Grande and Marsa, we’re comfortable with the market outlook. The goal is to manage exposure to the softening projected in the market by the later part of the decade. The market remains responsive, and we aim to have clarity on our positioning as we finalize more contracts.

Very clear. Thank you.

The next question is from Lucas Herrmann of BNP Paribas. Please go ahead.

Thanks very much for your time. Two, if I might. One, the first is just to JP, the hybrids, 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 fascinating to see the extent to which gasoline demand is perhaps come to come under pressure from EVs. You've obviously had a fair amount of switching diesel into gas, LNG trucks, et cetera, et cetera, and demand increasingly feels. So it's coming from the chemical industry. And perhaps negating crude. But just – I mean, just your own thoughts and insights into how you see Chinese oil demand developing next few years? Thank you.

Yes. We decided not to renew €1.5 billion in the second quarter because we used the flexibility offered by the rating agencies, if you can demonstrate that without renewing your rating, your credit is not affected. We see – because we have over €2.5 billion next year in our agri portfolio. So we have to discuss with the rating agencies to see what we can do.

On China, insights about forecasts are difficult when you are not in the market. Generally, my view is that oil demand globally continues to be driven by China, even as India is also a growing country. I would take the assumption of 0.8% per year as a reasonable assumption until we see a real reversal. We are hearing much about the slowdown in the Chinese economy. I believe the market remains active. While it’s true earnings from EV sales look impressive, many manufacturers communicate growth in traditional petrol car sales as well. It’s somewhat similar across markets: customers want reliable cars regardless of their regions. An interesting observation, LNG is becoming increasingly significant for trucks, and I believe this trend will sustain. However, I don’t see a quick decline in oil market demand; thus, keeping a 1% growth in oil demand per year seems reasonable. In general, the LNG market could expand from a current 400 million-ton market to a 600 million-ton market rapidly within four or five years if supply constraints don't impede that. More countries are poised to begin accepting LNG this year.

Okay. Thanks very much for the comments.

The next question is from Alastair Syme of Citigroup. Please go ahead.

Thank you, Patrick. Just one question. I just wanted to get your sense on the competitiveness of opportunities in renewables. I know there was another German lease bid auction recently that you are one of the two bidders or winning bidders, but it was quite strange. I think your German partner probably pulled out because they thought the auction had become too expensive. Can you give us a sense of where that difference lies?

If we made the bid but you think it’s competitive otherwise, we wouldn’t do it. The block we acquired is next to the one we secured in the first round, allowing us to realize synergies in development. Fundamentally, we believe that our strategy aligns well with the renewable developments in Germany, especially considering the current energy policy in the country, which has moved away from nuclear and coal to focus on renewables and gas. The increase in gas prices in Europe is likely to drive electricity prices up. We are building a comprehensive integrated portfolio in Germany.

Okay, I look forward to October. In the meantime, enjoy the Olympics.

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. Can I come back to the topic of green hydrogen and that deal that you’ve just announced with RWE? Can you comment a little bit about the competitiveness of the industry? You are 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 current available prices. So I'd 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 behind, let's say, improving the currency that you have in New York. And if I can sneak in a third question, 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 more than 40% as CFO, which means in terms of shareholder distributions?

On the last question, I think you have the answer in Jean-Pierre's speech. He told you that we are confident we could come back to a gearing of 7% or 8%. More than 40% is our objective. To answer your first question regarding green hydrogen: It's complex. We have different ways to provide green hydrogen to refineries based on the RFNBO regulation in Europe, which adds economic value due to avoiding emissions trading system (ETS) taxes. We are investigating both tolling agreements and direct investments in electrolyzers, as well as potential imports from abroad. Our deals will create value not just by avoiding the ETS but also by capturing the RFNBO products' added value. It's about leveraging the new economic framework established by European regulations. We are committed to making sure our green hydrogen is competitively sourced. Regarding U.S. M&A, we aim to improve our shares for your benefit. Our rich portfolio of projects is our primary focus right now, with less emphasis on M&A.

Thanks very much, Patrick.

The next question is from Matt Lofting of JPMorgan. Please go ahead.

Hi, thanks for taking the questions. Two, 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 in the context of oil and gas growth, 2% – 2% to 3% CAGR to 2028 or the 4% energy production growth to 2030. How significant is the derisking of those objectives being through the last sort of six months, nine months, and what 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 strength around sort of China and India from a demand perspective? To what degree does TotalEnergies see that strength as seasonal versus structural? Thank you.

On the first question, again, we set this objective for the next five years in September 2023, targeting 2% to 3% annual growth, and we were clear about our need to sanction projects. Most of the work has been done during the first six months. We have projects in Brazil and Angola. Suriname will come soon again, and we are also progressing in Iraq. Regarding revenue forecast, we have multiple options in the portfolio. I'm even more confident now than I was in July 2024 due to the progress we've made on project sanctions. The LNG demand from India and China is structural; we see India enhancing its LNG infrastructure, allowing diverse industries to develop around gas. In China, we are witnessing a push toward transportation-based gas consumption. I believe that overall, the growth trajectory is grounded in structural demand rather than seasonal fluctuations. The demand could increase to a good extent in Southeast Asia as well.

Super. Thanks very much.

The next question is from Henri Patricot of UBS. Please go ahead.

Yes. I want to thank you for the update. Two questions, please. Maybe the first one, just coming back on cost. I was wondering if you can comment on the inflationary pressure that you’re seeing. You mentioned P&G, LNG, where we saw costs escalate and postponed the project. Or are you seeing inflationary pressure in a broader context? And then secondly, just a quick question on the CapEx guidance for the year? Where should you expect cash outflows related to acquisitions to be offset by cash inflows from disposals this year? Thank you.

Regarding inflation, I would say we are 20% higher in most costs compared to the low point seen in 2020. However, we can manage this increase. Papua LNG is somewhat isolated, and we decided to go with larger suppliers, especially in Asia, to counter some costs. The general inflation is stabilizing; for instance, the rig market is beginning to become stable, so we don't see significant challenges ahead. Yes, the guidance remains at $17 billion to $18 billion for CapEx.

Okay. And CapEx points you should be also within that range.

Yes.

The next question is from Paul Cheng of Scotiabank. Please go ahead.

Hi. Good morning. Two questions, please. I think this – the first one is for Jean-Pierre. In your press release, you said the integrated power result was impacted by some seasonality like in Europe and Chesapeake seasonal demand. Can you help us understand how big that impact is? And maybe in general, what type of other visible seasonal patterns we should expect in the integrated power business for you? Second question, I think this is for Patrick. Any update for business?

The main driver behind my comment was that gas plants were amortized less in summer for obvious reasons compared to winter.

Can you quantify how big is that impact? And also other than that, is there any other seasonal pattern in the other quarters that we should be aware of?

We are young in integrated power, so we don't yet have enough history of results for precise answers. I can say the gas plant level of use in Europe was very low – less than 10% compared to something around 40% previously, which impacted the results. And when we look at the figures, this was a primary explanation.

Namibia – we finished the appraisal of Venus. We are now working on the development scheme, managing the gas quantities wisely. Our engineers are working on it to ensure we can effectively develop the oil pool within a breakeven of less than $30 per barrel. Updating you will likely happen by the end of 2025.

Very good. Thank you.

The next question is from Bertrand Hodee of Kepler Cheuvreux. Please go ahead.

Thanks for taking my question. Two, if I may. First, on Suriname. Can you confirm and I just suppose your earlier comment points to an FID for 2024? But can you still achieve the $9 billion budget you've outlined last year? The second question is on LNG. You've signed a 2 million-ton long-term contracts to Asian customers, but you have taken a lot of offtake commitments in the last, let's say, 15 months including real and of 5 billion tons QAC. Now do you have a target in terms of volumes you would like to secure on a long-term basis for Asian customers?

Regarding the Suriname FID timeline, we're progressing. I can't confirm specific figures yet, but I assure you that all development costs or CapEx will be maintained lower than $20 per barrel. We want to secure as high a percentage as possible of the contract on a brand basis rather than on Henry Hub. Our target is not necessarily fixed at 15 or 20 years, but we would be aiming for at least 80% in the medium-term contracts.

Thank you.

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 on some very warm days. I was wondering how you can capture those. And the second question was you explained as your utilization rate for the European natural gas power plants was very low? Or was it in the U.S.

On the contrary, we know that the gas-fired power plants we have acquired need climatization. The heat wave in the U.S. has been strong. The results in Q1 will likely be better, as these gas plants are being utilized at a very high rate. We acquire flexible assets, and the summer's performance reflects this. We believe our investments will also be beneficial moving forward.

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 for a decline. But I'm wondering if it stays at this level for longer? Is there a level that it increases to that impacts the decisions around the distributions you’re paying out, specifically regarding buyback pace? And then my other question is just on the quarter, where we saw E&P OpEx move a few hundred million dollars higher quarter-over-quarter despite production being relatively flat. I was wondering what drove that if that's structural or if that should reverse next quarter? Thanks.

The OpEx of E&P, we are lower than $5 per barrel. Regarding gearing, 10% gearing or 8% gearing does not affect our buyback decisions. We previously had a larger working capital build, which stabilizes over the year. We do maintain a balance, and the board's focus remains over 40% payout on shareholder distributions. I assure you, the working capital is under control, ensuring we maintain cash flow through the coming quarters.

Great. Thanks.

This was the last question. Back to you for any closing remarks you may have.

Thank you again. I think we have delivered our roadmap for the year. As I insisted, we have made progress on our strategy and execution toward our growth aspirations from 2023 to 2028 and can demonstrate how our portfolio is growing while also being resilient to various market volatilities such as LNG fluctuations and inflation costs. I wish to see you all on October 2 in New York for further discussions and presentations on our journey forward. Thank you to all, and enjoy your holidays.