Ladies and gentlemen, welcome to TotalEnergies' second quarter and first half 2026 results conference call. I 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. Hello, everybody. Good afternoon or good morning for those who are in the U.S.. Before Jean-Pierre will go through the details of the second quarter financial, I would like first to make some few opening comments. Starting obviously with the current conflict in the Middle East, which has picked up again in the last few days, and which is very impacting our markets and our operations and our perspectives. Although we were all hoping in mid-June that a resolution could be envisaged with the signature of the MOU and ceasefire between the U.S. and Iran. The situation has remained, to say the least, extremely volatile, with the Strait of Hormuz being an intermittent battleground, where the risk premium to navigate in these waters is increasingly high. Some are even beginning to consider that this could become a new normal, with the strait opening on and off, depending on level of tensions between the parties. This unstable and chaotic environment has been prevailing for the second quarter, but I would say the last 15 days in June, where we have seen some quite interesting reactions of the market, with crude oil going down very quickly, but products going through the roof at the same time. We don't know how long this conflict will continue. We have no specific information. I don't know if anybody knows, by the way. Of course, for us, safety of our teams will remain our utmost priority. As Jean-Pierre will show you in a moment, we can say we have managed this quarter to deliver, once again, strong results and cash flows from both our strategic pillars. Thanks to the strong performance of the teams who managed to capture very favorable market conditions for many of the energies we are producing and selling. The oil prices rose above $100 per barrel, even if differentials are widened, while refining petrochemicals, biofuel margins, but also distribution margins were increased, with some even reaching historic levels. Gas, LNG, electricity were also at strong levels. Once again, TotalEnergies is demonstrating its capacity to capture these margins and high prices, leveraging the integrated and diversified business model along the value chains of oil, gas, and electricity. First, for oil upstream and downstream businesses have been performing very strongly at the same time, which is not so frequent, in fact, since quite often one benefits from a supportive environment at the expense of the other. Currently, both are capturing high prices and margins, given the tensions on global demand for products. As we speak, integrated margins this morning are around $130 per barrel, Brent crude oil around $95 per barrel, and margins at $35 per barrel. E&P delivered a strong quarter in terms of productions, thanks to a solid 4% organic growth, higher than our forecast, coming from a rich and diversified portfolio of projects, which was planned, in particular from Brazil, U.S., and Libya. I must say it was very good from a strong operational performance limiting, I would say, the unexpected stoppage of the production. It was a very good performance from an operational point of view. All that allow us to partly compensate the production losses in the Middle East. E&P has been delivering, once again, this quarter, a strong cash flow from operation. Despite as well, I would say, there was a difference in the Middle East between the production reported and the capacity to lift these productions, which impacted because the lifting in the Gulf, of course, was very limited by access to Strait of Hormuz. Looking forward on the Middle East situation, beginning of July, end of June, I would say the productions were going up quite quickly, and we had limitations, I would say only 5% of our global production. This weekend, after the conflict came back, we were more back to 8%- 10% of limitations. Difficult. I think we say 5%-10% in our perspective. It will obviously depend on the way that the conflict will develop. Again, it's not only production for us, also lifting, offloading the crude oil, which might be affected. When we look to what happened in the second quarter, the real offloading was in fact affected as per our guidance at 15% of our production. We'll see what will happen for this quarter. Refining and chemicals performed in an exceptional way, I must say, leveraging market conditions, managing well the tensions on supply of refined products to maximize capturing margins. Refiners have adjusted the way they use their plants in the second quarter to prioritize, in particular, production of diesel and jet fuel, which were offering higher margins. Also by doing that, contributing to security of supply of France and Europe. This performance was achieved, although some of our facilities have been impacted by events outside of our control, like the SATORP refinery in Saudi Arabia, which was hit in mid-April, if I remember well, by some drones, and which is back today at 70% of capacity and full capacity by end of the third quarter is expecting. Also Port Arthur in the U.S. suffered, unfortunately, in June from a lightning strike during a tropical storm and now is progressively coming back to normal production levels. Our crude oil and petroleum products trading activities have been very successful for the second quarter in a row with a strong performance and made another $500 million, I would say, over performance on top of our usual secure performance of $500 million. Last but not least, on the downstream, marketing and services has reported the best-ever quarter, driven by the positive impact of the seasonality in Europe, but also higher, unique margins, in particular, on products like lubricants. After a strong outperformance in the first quarter, our gas trading activities results in the second quarter were not good, to be clear, and impacted by flat- to- declining European market conditions, whereas our traders were positioned to see the more supportive European gas environment in line with supply- demand fundamental expectations. Our traders took a long position on gas, thinking being bullish on the market, which seems to be reasonable because many indications were pointing to gas prices increasing because of lower supply out of the Middle East and from Qatar, because European inventories were low at less than 15%, below the five-year average. These factors did not materialize during the second quarter. Even, in fact, prices have declined through the quarter leading to weaker or poor results from the trading business. The story is however not over. As you have probably seen now, gas prices in Europe are volatile, and as our traders are rightly stubborn since early July, their gas trading results are following, and we will be back to some overperformance again. On our second pillar, electricity, there was multiple good news during this quarter. Integrated Power delivered one of its best quarters ever with a strong cash flow. In fact, the second best in 2024, even in the absence of farm downs during this quarter. It was supported by the closing of the transaction with EPH in April, one month earlier or one to two months earlier than expected, and the cash flow coming from EPH was as per the expectations. The strong deliveries on almost all fronts, but gas trading for once. We have generated at the company level next to $10 billion this quarter, which has been allocated in a very consistent manner as I've announced to you last April during the call for the first quarter. First, of course, we are deleveraging down to a gearing ratio of 13%, which show an improvement of 2.4 percentage points quarter-to-quarter, benefiting from a $3.3 billion reduction in net debt and also a $1.2 billion working capital release. Second, of course, we have confirmed the increase of our interim quarterly dividend by 5.9% to EUR 0.9 per share, which places TotalEnergies once again in the leading pack of the growing dividend companies. Along this quarter, our cash generation has also allowed us to sustain our production growth targets with disciplined capital investment of $3.4 billion, comforting our annual guidance of $15 billion, and also to increase, as announced, our buybacks to $1.5 billion during the second quarter. The Board has authorized us to maintain this buyback with another $1.5 billion for the third quarter. With all this good news, I now hand it over to Jean-Pierre, who has an easy work to go through the details of second quarter financial results. Okay. Thank you, Patrick. I will start by commenting on the price environment in the second quarter 2026 versus the first quarter. We capture high commodity prices, although gradually decreasing over the quarter. Brent averaged $104 per barrel during the second quarter versus $81 per barrel in the first quarter, meaning plus $23 per barrel, more than 25%. While average liquid price was up by $18 per barrel due to widened differential and a lifting schedule weighted towards the end of the quarter in a crude market which softened in June in the context of the ceasefire in the Middle East. TTF averaged $15.6 per MMBtu versus $13.7 per MMBtu, and our average LNG price increased by 20% at $10.20 per MMBtu. Oil prices started to impact LNG prices with one to two months of lag effects according to LNG pricing formulas. Finally, the European refining margins increased by $13.50 per barrel on average over the quarter. In this price environment, the company reported very strong financial results, increasingly by almost 15% compared to the first quarter. With second quarter 2026 cash flow of $9.8 billion and adjusted net income increasing to $6 billion. These results were possible because of the strong operational performance of all businesses, demonstrating the company's ability to fully capture the environment upsides. Upstream delivered an underlying accretive production growth of over 4% year-on-year, which is above the annual 3% guidance and partially offsetting the production loss in the Middle East. Downstream, a very good operational performance, as explained by Patrick from our refineries, which has been deliberately geared towards maximizing distillate production, diesel, jet fuel, to capture higher refining margins. Integrated power cash flow generation increased by 25% over the quarter, supported by contribution of EPH assets in line with expectation, since the closing of the transaction at the end of April. TotalEnergies generated this very strong result, the highest since the end of 2022, despite two challenges. Oil production from the Middle East was higher than originally expected. A significant portion of this production could not be lifted during the quarter and is recognized in E&P results based on the crude price from June, meaning less than $70 per barrel. Our gas trading underperformed after an overperformance in the first quarter because of the decline in gas price through the quarter, as explained by Patrick. TotalEnergies has delivered strong profitability this quarter with return on equity at 15.9% and a ROACE close to 14%. Now moving to the business segment, starting with hydrocarbons. On production on a year-on-year basis, excluding the impact of the Middle East conflict, second quarter hydrocarbons production increased by more than 4%, above the guidance provided of 3% for 2026, benefiting from the ramp-up of the project started since the beginning of 2025 and from an operational improved facility availability. The impact of the conflict in the Middle East is around 210,000 boepd over the quarter, below the guidance communicated last quarter of 360.000 boepd, due to the company's production ramp-up in offshore United Arab Emirates and the restart of production in the other countries in the region during June. Although physical lifting turned out to be in line with the guidance, with an impact of 350,000 boepd. Looking forward, we expect to maintain a strong momentum with oil and gas production in the first quarter, excluding the Middle East impact, expected to grow around 3% compared to the third quarter of 2025, in line with the annual growth guidance. Turning on the quarterly results and starting with E&P results, the segments generated an adjusted net operating income of $3.2 billion this quarter, up by 25% quarter-to-quarter, capturing the increase in average liquid price of $17.90 per barrel over the quarter, demonstrating the accretive new project contributing this quarter to the yearly production growth. Similarly, cash flow reached $5.8 billion, up 27% quarter-to-quarter. On the cost side, very important as well, once again, we maintain our leadership with an average OpEx per barrel equivalent below $5 in the second quarter. On integrated LNG. The LNG production decreased by 10% quarter-to-quarter, mainly due to shutting production in Qatar related to the Middle East conflict. In contrast to the outperformance in the first quarter, the second quarter was impacted by the underperformance of gas trading activities in an overall flat or even bearish European markets, reflecting the significantly decreased adjusted net operating income and the cash flow of the segment quarter-to-quarter of $0.8 billion. Given the evolution of oil and gas prices in recent months and the lag effects on pricing formula, the company anticipates an average LNG selling price of above $11.5 MMBtu for the third quarter of 2026. As we execute our consistent strategy in LNG, the main milestone of the quarter was the start-up of Energia Costa Azul LNG plant on the Pacific Coast of Mexico, strengthening the diversification of the LNG portfolio of the company towards the Asian markets. TotalEnergies loaded the first cargo at ECA LNG and shipped it to the Asian markets, where the company pursued strategy of signing long-term oil index LNG contract with new clients in China or in Japan. Turning now to integrated power. Net power generation increased to 14.8 TWh, up 28% year-on-year, driven by an increase of nearly 15% in generation from renewable sources, reflecting growth in installed capacity and a 2 TWh increase in production from flexible gas-fired capacity resulting notably from the completion of the transaction with EPH and of April. TotalEnergies is on track to reach its annual objective in integrated power, in particular to generate more than 60 TWh over the year. Cash flow from operation was above $700 million, supported by the contribution again of EPH assets, in line with expectation since the closing of the transaction. This quarter, again, we provide more granularity in the integrated power financial performance with a split in cash flow between what we call production assets, meaning renewables and gas-fired power plants, and sale activity, B2B, B2C, and trading. The former contributed 60% of the cash flow, and the latter contributed 40%. TTEP, the new venture with EPH, will continue providing its growing contribution to the company's results throughout the year, in line with expectation. As TTEP has st arted contributing in the second quarter, we said in the first quarter that integrated power should benefit in 2026 from 10 TWh of net power production, in line with the 15 TWh guidance given for a full- year, and more than $500 million contribution to available cash flow. Moving to downstream. During the second quarter, Refining and Chemicals was able to fully capture the increase in refining and petrochemical margins, notably adapting the refinery run to produce more distillates. Overall, for Refining and Chemicals, adjusted net operating income was up by $200 million quarter-to-quarter to $1.8 billion, and cash flow reached $2 billion. Marketing and Services delivered outstanding results, the best in at least 10 years, driven by the positive impact of the seasonality in Europe and the higher unit margin, as noted by Patrick, notably on lubricants. Adjusted net operating income was up 21% year-on-year at $500 million, and cash flow close to $850 million, up 19% year-on-year. Moving to the company level and starting with working cap. Working capital decreased by $1.2 billion during the second quarter, largely driven by the reversal of the first quarter build-up with the lower hydrocarbon prices at the end of the second quarter compared to the end of the first quarter. The company has kept the course for capital expenditure, with net investments amounting to $3.4 billion in the second quarter, with a contribution of net disposal to $1.2 billion. This, as explained by Patrick, comfort our guidance for full- year 2026 net investments level of $15 billion. As a result, the gearing is improved by more than 2 points to reach 13.1% at the end of the quarter, reflecting a reduction in net debt of $3.3 billion. To conclude, once again this quarter, the integrated model of TotalEnergies demonstrated its ability to capture higher prices and higher margins with a growing cash flow to support the deleveraging of the company, our shareholder distribution, with a clear priority to the dividend and the CapEx to deliver our growth. I think now we can open the line for questions. 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 and 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 the star and zero key. Once again, star and two. Once again, please press star and one if you wish to ask a question. The first question is from Martijn Rats, Morgan Stanley. Hi. Hello. Two questions, if I may. I know there's an awful lot of attention, of course, on the Middle East. I wanted to ask you a quick one about Namibia. It's still very important for Total. Where do you stand on the FID of Venus versus the completion of the transaction with Galp on Mopane? I was hoping you could say a few words about that. Secondly, I wanted to ask you about the payout ratio for this year. The guidance of more than 40%. I think we're sort of tracking below that so far. Of course, you see volatile macro environment. It's perhaps no surprise. The payout guidance, over which period should we expect that to be realized? Would you still expect to have more than a 40% payout over the year, or should that become a longer-term target? Okay. Thank you, Martijn, for the first question. I will be more precise. On the Galp transaction related to Mopane versus Venus, we have received, at the end of last week, the official approval of the Ministry of Energy of Namibia. We are just, in fact, finalizing the last paper to close the deal potentially tonight or tomorrow. Your question came at the right time. That's important, of course, because this fact that we will be on both developments as operator has a strong value for us in order to engage with the first FID. On the FID of Venus, I would say there are intense discussions as well. We have a joint target between the government of Namibia and the consortium to sanction it by end of July. There are discussions progressing. We'll see if we can conclude in July or if we need to have a little more time. Technically, I think we have selected all contractors. We are ready to take the FID subject to finalizing discussions with the government of Namibia. There has been some progress. Still some progress to be done. Generally, it's when the last minute, you can conclude. We'll see if we can do it. Otherwise, we'll wait. I would say reasonably optimistic that all the parties, there is a joint interest clearly, and in particular, the Namibian authorities are fundamentally supportive to have a strong operator being able to capitalize on synergies between the projects. I remind you that now that Mopane has been approved and will be closed, the next step is to engage in the second half to appraise Mopane. We have three wells in 2027. The FID will be taken in 2028. All that as we engage in a strong momentum. Clearly for us, Namibia will begin and is becoming a very important hub for future growth, not only to 2030, beyond 2030. On the other topics, yes, we are clear. We are targeting 40% of payout. We have increased the buyback level and the dividend level between the first quarter and the second quarter. I don't know where we'll go, to be honest. You could say there was a little cautiousness in the fact we have raised from $750 million to $1.5 billion. We maintain the $1.5 billion for the next quarter. I can tell that we were quite impressed also when the MOU was signed in June by the quick drop of the crude oil price down to $70. It's difficult, honestly, to anticipate what will be the cash flow for the second half of the year. Of course, we will be globally above the guidance we gave. I gave even to you end of April, I think I mentioned a cash flow guidance of $80 per barrel, $7 per barrel, $7 per barrel refining margin of $32 billion obviously will be higher than that. Where will it land between $35 billion-$40 billion? I don't know. It's difficult to guess. We can make the math like you. If we were at $35 billion, there is a miss. I mean, a miss, not a miss. There is a question of $1 billion, one a little more, around $1 billion to increase in the return to shareholders. $1 billion in the last quarter, we'll see, and there will be a debate at the Board at the different ways we could imagine to execute it. I think, again, my message to you is, first, it's a good topic because that means that we are generating more cash flow than compared to the guidance we gave you in February. It's a matter of, I would say, a rich company. It's a good topic. The idea that we will get to 40% is really on the yearly basis. I remind you, by the way, that we have quite an advance if you want to make it in a multi-year case, as you suggested in your question. I think the last year we were at 55%, the previous year around 50% or 53%. If I make it on multi-year, which is not the case because we are simple guys, but we are quite in advance compared to 40%. Again, consider that 40% guidance is guiding the Board. Again, the Board is also, as I was explaining you last quarter, looking, thanks to your support, with your support and your strong guidance last year at the same period of the year to the gearing ratio. Going down to 10% is quite also an objective for the company, and we might achieve it this year. That's the equation of the capital distribution, I would say, for the Board. I think we will manage that as we've done that regularly and respecting our different, I would say, stakeholders. Great. Thank you. The next question is from Michele Della Vigna, Goldman Sachs. Thank you very much. I wanted to ask two questions. The first one is if you have an update on the two giant oil developments you're operating in Uganda and Suriname. The second one is more of a macro question. I was wondering if you have a view on China demand. We've seen a drop of about 5 MMbpd in imports since the beginning of the conflict. It's very difficult to unpick what is the stocking demand, substitution demand, distraction. I was just wondering if you had any view of how to think about it. Thank you. Okay. First question, on Uganda. Okay. We are, I would say, in the last six months of development. I would say we expect the crude oil production to start before the end of the year. I would say 2027 will be the year where we reach a plateau. We have two developments. We have Tilenga on one side and the other one, the offshore is the main one. Kingfisher, I think is even ready to start up by September, if my information are good. The pipeline is also ready by, I would say, September. We might start, in fact, in the next quarter. The production at a rate, which is, I think in future was around 60,000 bpd. Tilenga will come ramping- up, I would say, on the first half of 2027. Full plateau for me is by mid 2027. This is where we are. By the way, an opportunity for me, and we will follow that carefully. Of course, Uganda is affected today by a disease, Ebola. If it was not the case, we think that we might organize If it stop, we might organize a field trip with some of you. The ones who are brave to go to Uganda in one year, in September 2027. Uganda, for me, now it's a matter of finalizing and turning the wells on. On Suriname, things are moving very well, I would say. We confirm that the production will start up by first half 2028. That's where we are according to planning I have. It was our first quarter, maybe second quarter, but we are in first half 2028 and the news of the construction. It has already progressed by 40%. We are at 40% advancement, the FPSO in the yard is building correctly. I would say, this is more classical. It is more complex to execute an onshore project than an offshore one. We are in Suriname, we are in a project which TotalEnergies, a deep water project. We know how to execute them. China, it is very interesting demand. Of course, we have all been surprised when we discovered the statistics of May and June, I would say. Where in fact, you are right. The refinery runs went down from 15.5 MMbpd in February to 12.5 MMbpd in June. Clearly with the policy, which was first I remind you that the Chinese authorities have decided very quickly to stop exporting products out of China. They reduced the run- rate of the refineries in China by 10%, down to 90%, I would say. Voluntary reduction of Chinese. It was more affecting the export. The domestic demand is difficult to say that it is a domestic demand disruption. I would not say that. It is also true probably that, what we are sure is that we observe it. It seems that there is some, I would say, turnaround on Chinese refinery in July, August and summertime. We don't expect, in fact, much increase of this demand from China. It is true that when you look at that, you can consider that the system in China has quite an impact on the oil market. Probably, you know, we were commenting in April the fact that the Strait of Hormuz blockade was representing 10 MMbpd to 12 MMbpd of the market. The Chinese, by themselves, with their policy, I would say, absorbed 4 MMbpd. If you add on that the U.S. has released almost 2 MMbpd of the SPR. They have solved, the two countries, I would say, have solved almost 60% of the problem for. That is probably why, by the way, the price of oil went up to $120 per barrel, not so high. For the coming months, Michele, you can observe like me, that we are back to the blockade today. It is no vessels, no tankers are crossing Strait of Hormuz. We are back to the situation. I know that the Chinese have announced that they will allow again some few refineries to export some few products. It was during, I would say, the calm, the quiet period at Hormuz. Today, we can imagine that again, it might not be the case again with these events. That is what I can comment. For sure, less exports, domestic demand destruction, difficult to have data on this one. Thank you. The next question is from Biraj Borkhataria, RBC. Hi there. Thanks for taking my question. Just two on your LNG business. In June, there were reports around a Russian decree to authorize a sale of 10% of Arctic LNG 2, I think related to the European sanctions. I don't believe you have commented, but are you aware and are you planning to exit there? Related to that, are you any clearer on the sort of legal language around EU sanctions and what it means for Yamal at this point? I know I asked with full year results and it wasn't quite clear exactly what it would mean, and there's been some conflicting reports. Any color there would be helpful. Thank you. Thank you, Biraj, for your questions. I know that you have a specific interest for Russian matters, for good reasons, by the way. Arctic LNG 2. As you know, I remind you that we decided in 2022, it was very early in March, in the accounts of March 31st, 2022, shortly after the war. We recorded an impairment of $4.1 billion, which was in fact concerning notably Arctic LNG 2, a full write-off. Secondly, that Arctic LNG 2 has been placed under sanctions by U.S. authority on the 2nd of November 2023. As a result, immediately, we suspended procedures in accordance with existing contracts. In consequence, in fact, all rights, obligations under these contracts related to Arctic LNG 2 have been suspended since November 2023. In such a context, Novatek approached us indeed and initiated discussions for the transfer of our 10% in Arctic LNG 2 to one of our own subsidiaries, Nordline. This has been publicly authorized, as you noticed, by a special decision of the Russian presidency in June. In fact, given this context of Arctic LNG 2, we on our side, consider that it's a joint interest of TotalEnergies and Novatek to dispose of our Arctic LNG 2 shares, which again, were fully impaired in 2022. We have notified our partners and lenders, and we expect the transfer process initiated by Novatek to be completed in the near term. The Arctic LNG 2 chapter will be over for TotalEnergies in such a context. The second question, I would love to be able to answer to you, but we are waiting to see what is the legal language precisely. As you have, there was some press news this morning that there was intense discussion about the new sanctions package at Brussels. Among these different topics, and we are not part of everything, even if we try to understand, we are not in the room. There was a debate which came from, I would say, the Greek authorities, which were claiming that the Greek LNG tankers should be allowed to transport some LNG from Russia if it was to be offloaded outside of the EU. That was basically the case. It seems that there is a legal language, but again, which could, in fact, have an impact on the Yamal LNG, accordingly what was said, and which could, in fact, allow, I would say some transfer and purchase of Yamal LNG, if we were using EU LNG tankers outside of EU, again. A specific case, so it's a little complex story. That might have, yes, an impact on the fact that we, in fact, if it is the case, that means that TotalEnergies could not use a force majeure to say to, like it was until now, because until now, there could we, in fact, with the regulations which were in place, which were banning the LNG exports to EU. There was a question mark. I made that comment, I think, in April to all of you, or in February, I remember. We are questioning, there was a different interpretation of the European sanctions, that even a EU company could not purchase any of Russian LNG, either for EU or outside of EU. It seems that the new language could, in fact, clarify it in a way that it could be done outside of EU if we use some EU LNG tankers, in fact. Which in fact would be that the interest of EU companies would, say, some be preserved independently of this, if it's outside of EU. Again, I'm just commenting some verbal information. We have been in contact with different, I think the final resolution will be delivered probably tonight or tomorrow morning. They are drafting the last ones, we'll see what will be the outcome. Of course, we need to analyze it because we have a policy where we don't want to take any risk with sanctions. My comment, if that is the case, again, I think the interest of EU companies will be preserved, because honestly, to let Russian LNG being sold outside of the EU, not by EU companies, but only by our competitors, was a little odd to all the EU companies involved. Let's see. That's what I can tell you. We'll keep you aware, obviously, because it has some impact on our own business. We'll keep you aware of the situation. Thank you very much. The next question is from Doug Leggate of Wolfe Research. Thank you. Good afternoon, everybody. Patrick, I wonder if I could pick up on Martijn's prior question about cash returns and the 40% and so on. I think we would all agree probably this is a bit of a windfall environment, and maybe formulaic returns of capital. One could be forgiven if there was some flexibility there. My question is specifically around the hybrid bonds as opposed to the net debt target, and whether you would consider these windfalls as an opportunity to perhaps address some of that longer-term financing as part of your capital structure. That's my first question. I've got a follow-up on exploration, please. I should give that to Jean-Pierre, but I know that I'm still. To be honest, the hybrid bonds, for me, it's a debt. It's a debt, but it's not a debt. It's a quasi-debt with a low interest rate compared to what we can typically issue bonds. I don't make a lot of difference between the different bonds that we have issued. I would say it's around EUR 11 billion of 3% coupons. It's quite a cheap debt. Is it a priority to unwind all that? My answer will be clear. It's no. It's no, we have made some partial reimbursement, but it's not a priority. Again, we are more looking at, I would say, this year, I'm more looking to the global cost of our different bonds rather than this specific one, yeah. Maybe Jean-Pierre will say right. It is highly dependent on the market. If you could consider these cheap debts, there is no reason not to keep the hybrids in our portfolio. Of course, we highly dependent on the conditions, as Patrick explained. What is important for us is globally the cost of global debt, senior bond plus hybrids. That's very clear, guys. Thank you. The dynamic is Q15. Yeah. My follow-up, Patrick, is very specific on exploration. You hired Nicola out of Eni, and you have Mopane and Venus in Namibia. Back in 2016, Total drilled the only deep water well in Uruguay. Eni, late last year, farmed into Uruguay. It seems that activity there is picking up a bit. My question is, when you roll all that together, does Total any ambitions to move into Uruguay? Okay, Doug, you will need to ask the question to Nicola. To be honest, Nicola did not come to my office to tell me, we need absolutely to come back to Uruguay. To be clear, our own experience in Uruguay has been quite average, to be honest. In fact, it's a whole basin because this basin, which was the Pelotas basin, if I remember well, in fact, we drilled in Uruguay. We also drilled in the other side in Brazil, which was not as well quite a success. We made two drillings in this deep water basin there, which was honestly not very encouraging. I have noticed that there were some companies last year which went back. Nicola is quite excited by Namibia, by coming back on Suriname with [inaudible]. He has some other ideas or other African countries. Again, I discussed with him through your intermediary, Doug, if he wants to come back to Uruguay. As the CEO, the policy is quite clear. We allocate $1 billion per year to exploration and appraisal. This is my commitment to Nicola when we are in. I told him, it's up to you to decide where we will put the money. You have to share with you your convictions. If it's your ideas, we know, we follow that. By the way, when I was looking to potentially not buy it down, but the Venus case, looking to development, Venus development might generate quite a nice cash flow, paying many years of or like Suriname, the GranMorgu development will pay many years of exploration. That we need to keep in mind that it's in terms of cash generation. Added value exploration for me is a nice engine. Again, I trust Nicola that he will bring to us ideas. I don't know if it's Uruguay or not, until now, it's not Uruguay. Great. Thanks so much, Patrick. The next question is from Christopher Kuplent, Bank of America. Thank you very much. Just two quick questions from me, Patrick. The info that you've given us on the positioning of your gas traders is very helpful. What you expect on that side, now that you've got access to the EPH portfolio? The second question, as ever, I keep trying to get comments out of you on the state of the M&A market. Maybe now, we have a specific example that you know more about than we do, which is the Danish deal, which I believe is entirely operated by yourself. What do you think about this environment? You've made use of inorganic before. Is this an environment to sell or to buy? Any comment once again would be appreciated. Thank you. I commented to gas trading, gas trading has been, again, lower performance on trading. Just to tell you that now the position is, I would say, the winning one. On electricity, honestly, I don't have the visibility on that. Your question, of course, we have, as you know, the EPH deal is a deal where we are buying the assets, but we transform all assets in a tolling mode in order to have access to the electrons, in order to trade ourself around with electricity. In fact, today at this stage, all the assets have not been yet, all the tolling agreements have not yet been signed. We are working on it. I think the full potential of trading around the EPH deal is more for the fourth quarter than immediately, to be honest. Of course, we are expecting from that some additional value. In fact, we have some objective, and we were discussing that, by the way, with our trading electricity team last week during our five-year business plan. We have some objective, and we expect them to deliver. We are trading on two markets. There is the European market. There is one with which we are also trading in the U.S., which is a little more complex market, to be honest, because our position there is probably today still limited. We will need to find ways to increase the position in the U.S. if we want to be, I would say, profitable trading electricity in the U.S.. In Europe, we have quite a large portfolio today in different countries. We have some project expectations. The U.S., I would say, it's still a work being in progress, I would say, on this one. M&A market. I didn't have the time to analyze the price which was paid by Vår Energi to acquire the BlueNord energy. Probably I will receive a memo, but I was occupied by other matters these last days. It seems for me, the market today is more a seller- market than a buyer- market. With the price of crude oil price, which we have today, if you make a deal, or unless you have bigger now or schemes in which you will try to capture part of the potential upside, it's not a stable market. Before this crisis, I think you could imagine that the deals were done around to buy you around $70 per barrel. Today, to sell at $70 per barrel. On my side, to be honest, I would not be a seller today on these assets, on your assets, because we would not like to lose some upside. Selling is probably better today than buying. Yeah, it's fine, to come back to your deal. Again, I cannot comment the specific situation you mentioned. Maybe we have some pre-emption right. I don't know. I don't know the situation obviously. We'll look at it. As it is our assets and we operate with-- By the way, I'm not surprised because BlueNord was bought and by a fund, and it was quite clear to me that I met, by the way, the owner of BlueNord, when I was in Denmark a few months ago, and it was quite clear to me that they were willing to sell. For us, as TotalEnergies, we have already quite a big share, I would say, in these Danish underground assets. It's quite mature assets, to be honest. I think we are fine with what we have. Again, we'll look to this situation. Great. Much appreciated. Thank you. The next question is from Mark Wilson, Jefferies. Thank you. Regarding European projects, could I ask about the Cyprus project, Cronos Block 6, and what the expectations to move that one forward are, please? Secondly, on gas trading, yes, agree with others' helpful comments, you spoke to the European expectations for price moves there that didn't occur. Should we consider your gas trading business to be more of a regional-focused business rather than global? Obviously, oil material moves up and down and probably that enables that business. Should we think of your gas trading business as being a more European regional-focused one? Thank you. No, still not quite clear. No, we have a global gas trading. We are a big LNG, I would say, player. I just mentioned that there are different markets in the U.S., in Asia, of course. I just try to, in my comment, to tell you where we make the miss, the miss was more on the European anticipation on the TTF, where I think we are around $15 per MMBtu- $16 per MMBtu. End of March, we're around $17 per MMBtu. Since we are thinking it would go up to $19 per MMBtu- $20 per MMBtu, like it is going, by the way, today and in July, because we anticipated the impact on the market, both of the distraction from the Qatari production from the market and the, I would say as well, the fact that the inventory in Europe had to be rebuilt. In fact, what happened is that the market probably considered that it was to anticipate to grow to have a higher price because expecting maybe the Qatari disruption to stop, which happened in June, but came back in July. That there were time to have higher to grow the inventories. It's also true that the weather in Europe was quite, in fact, good in the second quarter. It's just to try to give you the main, the major, the one on which they took a position which appeared, which were in fact reversed, which were not the right ones. It does not mean at all that we are not a global one. I would say on the other markets, I didn't see any specific. We didn't see any, I would say, underperformance, I would say. We only see it on the European position. That's why I mentioned it. Don't draw this to the conclusion. Thank you for this question on Cronos. We are working on many FIDs. In fact, the end of July. The good news, and I think I must pay tribute to Eni, the operator, because we are at 50%. We have a big share, 50% like the operator, Eni. We work jointly, by the way, in the last six months to go to the FID. The good news is that I think we are working hard to, again, like on Venus, to finalize the FID by the end of July. It's a matter of, again, there is a lot, Cronos for everybody is an interesting development where we produce gas in Cyprus, and then we maximize existing infrastructures in terms of CapEx, because it's a subsea development. It will go to Zohr installations in Egypt to make the gas treatment, and then to Damietta LNG plant in Egypt. You can imagine there was a number of inter-governmental agreements and agreements with third parties to use all these existing installations. It's being done, honestly, and I think as [inaudible] discussed, we'll be able, probably at the end of next week, to announce that. It's good. It's an interesting project because at the end, for TotalEnergies, we have access to 1.4 million tons of LNG in Egypt, just in front of the European market. You can imagine that it's an interesting project from gas to LNG. For Cyprus as well, it's the first gas development in Cyprus, and maybe our scheme will open the door, will open the way to other valorization. It has been a long journey, but I think we are there, and we'll be happy to invest capital in the Cronos project. The next question is from Matt Lofting, JP Morgan. Thank you for taking the questions. Two, if I could, please. I wanted to first ask you about full-year operating cash flows. I think, Patrick, you said earlier, understandably, that you'd expect to be probably above the $32 billion for the full year that you mentioned in April. Obviously, the macro scenario is uncertain. If we were to stick to the sort of $80 per barrel, $15 MMBtu gas, and $7 per barrel refining that you used in April, where do you think full-year cash flows at that price deck would outturn on an underlying basis versus the $32 billion that you saw three months ago? Then secondly, I wanted to ask you about refining and security of supply of feedstock. Is the company able to access the appropriate feedstocks for the system as you look into the coming months? Is there a scenario where additional measures could be required from that perspective, particularly if conflict in the Middle East persists? Thank you. Okay. On the first question, it's quite easy to answer. The $32 billion, because we know what has been the improvement in the second quarter, would be raised to $34.5 billion. That's why I mentioned $35 billion, I think, in my answer to your colleague, the first question that I got. $34.5 billion- $35 billion would be in such an environment. I will say you can get it as a guidance. Again, we'll see if we are at $80 per barrel. Since the beginning of the year, we were a little higher. We are more on an average, I think, around $90.70 per barrel since the beginning. The last 30 days, we're at $76 per barrel. That's quite a spread. Between $75 per barrel and $90 per barrel, we'll see where we land. It's interesting. In these assumptions, $40 billion- $44.5 billion. The current forward curve is a moving target. It follows the spot one. I don't have the figure. I mentioned to you a range of $35 billion-$38 billion-$39 billion. If we were having a second half as the first half, you double it, you find $38 billion. It's a higher environment. It's not $80 per barrel, it's $90 per barrel. It's $90 per barrel. It's a refining margin of $15. It's $90 per barrel, $15 MMBtu, and TTF at $15 MMBtu as well, which was the average of the first half. If you replicate such an environment, you could imagine we should deliver around $38 billion instead of $35 billion. You have a range to where we could land, but I don't know, maybe it will be lower at the end. That's what I can tell you today. The second question, no, we have no problem of supplying feedstock to our refining system. Not at all. We are producing a lot of oil in Brazil, a lot of oil in Africa. In fact, our refinery, by the way, independently of Hormuz, in fact, in terms of crude supply, the Atlantic Basin or European refineries, which are on the Atlantic Basin, are generally supplied by crude oil coming from the Atlantic Basin. It's true that we like to have some sour crude coming from the Middle East to make more diesel because it's the best crude to produce diesel. There is a limited, but generally, Hormuz. Sorry, the sour crude from the Middle East is more going to Asian refineries, in fact, than to European ones. No, we have no concern on our side to feed our refining system. The only concern I could have is more around SATORP in Saudi Arabia, because first it has been hit. I hope it will not be hit again. We don't have the full capacity. Secondly, SATORP production is, of course, stranded in the Gulf. It has been quite well used by the Saudi system during the second quarter for domestic use because they had other refineries which were hit. From this perspective, we are running it for the domestic market, but we'll see what could happen if it's gone. That's the situation, but no security of supply for feedstock or system. Super. Thank you on both. The next question is from Lucas Herrmann, BNP Paribas. [crosstalk] Thanks very much, Patrick. This is a little conceptual perhaps, but one of the things that I think most of us or many of us are struggling with medium term at the moment is the fragmentation or fracturing within OPEC. The UAE having departed, Iraq talking about an incremental quota or changing its quota. If you think forwards about your own position, the potential for Iranian barrels to come back, more UAE to be available, Iraqi flows perhaps be larger, where does discipline sit with what remains of the rest of OPEC? How does that impact the way you think about allocation of capital to projects? Does it change anything in terms of how you feel about the robustness of oil markets, particularly at the bottom of the cycle? Secondly, if I might, and maybe this is just one that I should leave or we should leave for the strategy days, was simply to ask whether in light of the actions you've taken on Mopane or around Mopane, the addition of EPH, and the environment we're seeing in refining, in particular at the moment, that may be sustained, whether that's changed and altered your target of EUR 20 billion or so of free cash by 2030 in a $70 per barrel world. Thank you. Okay. The first question. It's good question for the investor presentation outlook in September, Lucas, where we speak more about strategy. The first one, what I see in terms of capital discipline, because of all what you described very rightly, it's very good to stick of the discipline to test all our projects at $50 per barrel. The answer, yes, you can infer that today we are in a world of high prices, but we could go in a way where everybody would like to produce more. Maybe, by the way, Saudi Arabia, like they've done in 2020, could do. Why not myself? If everybody wants to produce, we could do it again. If you remember what happened in 2020 when Saudi Arabia decided to close the market, I think some few peeps around them were quick to come back to more discipline. It's a matter of discipline. For us, honestly, I continue to believe, and we are. In the company, we are continuing to test the $50 per barrel. We planned the five-year business plan. We plan it at $60 per barrel. Yes, we test what happened at $80 per barrel or $70 per barrel, like you mentioned. Keeping the discipline and knowing that we are in a cyclical industry, I think it's just fundamental. All these events that you mentioned, I think are just confirming to me that we need to keep a discipline. That's what I would answer to you. That means as well that you should not be surprised that when we speak in end of September about, how we say, capital net investment, capital investments, you hear figures which are more or less in line, which will be not more or less, which will be in line with what we told you last year. We do not suddenly increase our CapEx because we have, on the short term, a higher environment. That it changed 2030, not really what you said, because Mopane, first, the production of Mopane is beyond 2030. Venus should start by end- 2030. I would say Venus, Mopane for me, it is 2030- 2035. We are working on it, there's no impact. EPH somewhere was part of our five-year business plan. We told you, we have just anticipated with EPH some of the CapEx we were willing to allocate to M&A in integrated power. It has been done, in fact it was modeled, even if EPH was not the deal which was modeled in our future cash flow by 2030. Balance and refining, frankly, I will not take it as granted. I'm still, maybe because I managed that business during three years, I'm a little more cautious of that. Today, we have an incredible situation where both markets are positive in the same direction. That's true, that on the products market, you have no products coming out of the Strait of Hormuz. The Russian situations with themselves, they stop exporting diesel, you have Russian disruption. You have a lot of impacts which are pushing up the product price. I don't think if Strait of Hormuz remains on and off, as I read that some authority said maybe it's a new normal. If it is the case, we'll not be in the $50 per barrel environment. We'll be elsewhere because there is no real cycle with an on and off Strait of Hormuz production. Of course, we are building and we are discussing today to invest in some of the pipelines projects which will allow to circumvent the Strait of Hormuz, which will take a few years. The balance of refining, I don't take it for granted for our planning by 2030. We'll come back to your question more precisely. For me, in fact, what we have worked since we met last year in September 2025, we have confirmed, in fact, it's more, we will come back to tell you fundamentally all our targets are confirming even strongly. Yes, the increase of free cash generation that we announced, which was more than $10 billion, an increase of more than $10 billion, will be confirmed. Far, this is one of the first messages in September, which is a confirmation of that. The second one will give you more color on beyond 2030, because in fact, we are working now beyond 2030. The company has two objectives, to deliver all the 2030 additional free cash, and we will do it, I can tell you, and we'll demonstrate why we are super confident, and you have some of the projects you mentioned. Working as well to continue the story, because the story of TotalEnergies' growth does not stop in 2030. The next question is from Naish Cui, Barclays. Hey, good afternoon. Thanks for taking my questions. Two, please. The first one is on the Middle East. Patrick, we watched some of your recent interviews with French media. I think you talk a lot about the importance of building more export pipelines in the UAE as well as other countries. I wonder if you could elaborate your thinking around the Middle East situation and TotalEnergies's longer-term strategy in the area, please. The second question is on power segment. You have built a successful power business, and you achieved one of the best quarters, as you mentioned earlier. Strategically, I wonder, what's your next ambition for this business? Thank you. Okay. On the Middle East, it's quite obvious to me. We are very well-positioned in Abu Dhabi, for example, and we just announced two very big projects, by the way. Maybe despite this war, we have been quite active in Abu Dhabi to reinforce the whole partnership and position of TotalEnergies together with ADNOC or XRG or Masdar. We have announced a joint with Masdar in all these renewable business in Asia. We have announced the Bab Gas Cap concession, which was an old dream for many people in the company to have access to the Bab Gas Cap. It's done. We've got partner. By the way, it's interesting to know that when in 2015 we signed the Bab concession onshore, some people were skeptical. Ten years after, we deliver the additional value, and it's because we were in the place together with our partners that we managed to go along with ADNOC. Thank you, by the way, to the trust that the Emirati authorities have given into the existing consortium. We have also announced the Umm Shaif Gas Cap. We have FID, I would say, yesterday, this week, in fact. We have FID together with ADNOC, and we have a 20% share. The Umm Shaif Gas Cap, which is also, by the way, not only gas, it's also liquids. All these gas cap, by the way, are gas projects, of course, but there are also quite good condensate projects. It's a liquid. When you need liquids, you need to have an outlet. It's clear to me, and Abu Dhabi has been very active. ADNOC has been very active, very reacting on we need to double the pipeline to Fujairah in order not only to accommodate future growth, but also to connect the offshore production. I think ADNOC is offering to partners to look at the projects, and we are looking to that very seriously. That's one part. The other part of interest for us is Iraq, because we have some production in Iraq. Iraq today, we have only one way to export. Almost not one way, I'm exaggerating, but fundamentally it's Basra, so it's in the Gulf. Being able to contribute and to see. There are some projects which are being announced and being studied from Iraq to Syria, and TotalEnergies is keen to join the projects, if possible, or to develop some. I think it's obvious to me that if we want tomorrow to come back to you and to say we want to continue to invest because it's cheap oil, which is true, and there is a lot of oil. We need to diversify our exit route. Otherwise, we would not do a proper business case. That's why I'm clear, and I think, by the way, for the countries themselves. Even, I think, if the conflicts were coming to an end quickly, we must absolutely keep that in mind and pursue the effort to have alternative routes for this oil. Integrated power, but the next ambition is to reach the 2030 target. It's not yet done. This year, we'll reach 60 TWh. We will reach more than 100 TWh. I think the 100 TWh is probably the low assumption for production by 2030. More importantly, we want to generate a net cash flow from this business. We said next year it will be net cash flow positive. This year it might be, but I would like to do it in a normal CapEx environment. We want to join not only more than zero, but I would say in our famous more than $10 billion free cash flow target by 2030. There was $2 billion coming from integrated power. The target is to deliver this $2 billion, and then beyond 2030, there are different options. Of course, we might continue to grow the business. The question is at which pace, in fact, and that will depend as well to opportunities. I think on this topic, the Board is very keen to really see the capacity of the company to deliver on our targets rather than planning big ambitions. Then it's not a matter, I would say of growth. It's a matter of value as well for the Board. I think for all our investors who have been supportive, not always, but today more supportive than before, by the way, to us to invest. I think we are right, because one of the lessons of the crisis, as you can observe in many countries, the new world is electrification. It's not green, by the way. It's electricity, electrification, domestic resource. It's also supported, of course, by all the data centers and AI growth. We are right to be and to continue to invest into this energy, which is a good complement to what we do, in particular on oil and gas, electricity and the gas to power connection is obvious. The ambition to continue to develop it in some geographies, just to, again, to frame completely, where we can develop the integrated model, where gas, renewable, customers, trading is possible. That means some few major European countries, the U.S., that will be the core, I would say, of our investments. If you add Brazil and India, I think you have the description. We are, in fact, today, the next ambition to be stronger in some markets where we can deliver the integration and the profitability. Very helpful. Thanks, Patrick. The next question is from Kim Fustier, HSBC. Hi. Good afternoon. Thanks for taking my questions. I wanted to go back to the Middle East. The production impact came in below your original guidance, thanks to the surprisingly fast ramp- ups in the UAE in June and maybe in Iraq as well. Now, with tensions rising again in the past couple of weeks, could that progress reverse? In other words, if the situation doesn't change from here, how soon could we see production shut-ins once again across the UAE and Iraq? Just staying with Iraq for a bit, just on the GGIP project. I think that Ratawi Phase 1 was supposed to be starting up sometime this year. Could you give us an update on this project? Obviously, does the renewed regional escalation pose any risks to the timing of the oil ramp-up, but also the other parts of that project, including the associated gas and the seawater project? Thank you. Okay. Thank you. I mentioned that I gave you some information in my opening comments to tell you that, I would say beginning of July, the production, I would say was in July, I would say until July 8th, in fact, until the blockade came back, the production was going up and the impact on our production was even around 5% only. The global production from the Middle East, if you consider that our base was around 650,000 bpd was by that time 550,000 bpd because there was an increase in many assets, in particular, of course, in the-- I would say Abu Dhabi assets were almost back to normal production, which demonstrate, by the way, that I remember the questions that I had during the months before the MOU. Is it quick to go back to the normal level? Yes, it's very quick. The wells in the Middle East are very easy to reopen and to produce. Abu Dhabi was back. I would say even Qatar was not fully back, in fact, on the LNG side because there was a sort of ramping up cautiousness on this one. Iraq, even Ratawi was back to, I would say, half of the production. Iraqi part was a little more, I would say. We are minimizing and we are ramping up quickly to come back to a normal level. Since July 8th, in fact, because of the situation when I was looking to the situation beginning of this week, again, the impact is more around the 8%-9% I mentioned during my opening speech because, of course, we cannot maintain such production if we cannot offtake. It's not a matter of wells, it's a matter of offtake. Because, again, when you produce at maximum, your tanks are full and then your system, it's all the logistics which are constraining the production. I would say that, of course. Again, by the way, of course, the LNG plant, Qatargas 2 in Qatar, which was ramping- up, has been shut down again. You have some impacts. Today, as I told you, that's why to guess today, I would say, to be clear, the guidance I will give you, if we were like in, we were in the second quarter, we could imagine the production would be with an impact of 10%, but the offtake would be unfortunately higher. Back to our initial guidance, when we gave you 15%, it was, in fact, in terms of physical offtake, it has been 15%, again, during the second quarter. Third quarter could be the same. Again, the lesson is, the good news is that if this Strait of Hormuz is open back again, we'll be able to ramp- up quickly. Of course, it is a condition to bring tankers and to offtake the production. All that is going together. That's what we face today. We had some during the few weeks of opening, we managed to get all our tankers out. We managed to have some tankers in and out, by the way, in order to load. I think we managed to load three tankers during that period. Again, now we are back to nil because it's not possible. Let's observe. The second question, Ratawi. Ratawi, I think they are different story. The first phase that we are planning to start up, we were expecting the first half. Of course, we are delaying because there have been some impact. By the way, Ratawi cannot produce fully today, and it has been some impact because some equipment, et cetera, of course. Today we are, I would say, targeting end of third quarter, so September. Will it be possible? Honestly, we don't have some events under control. The other projects are progressing. All the projects have been launched, and all the contracts have been awarded. We have people on the ground for the seawater project, for the associated gas project, for the second phase of Ratawi. By the way, we are working as well, and we have good news in terms of productivity of the wells, which think will be good that we have than the first phase one day. All that is just being impacted, I would say, in terms of execution, because a lot of equipment. In fact, one of the first of all, everybody spoke about crude oil transit and products refined, product transit, but there was also an impact on the equipment, either one way or the other way. We have transported a lot of equipment by road, but for the larger ones, it's not easy to do, and so even it's still not possible. That's the situation. We are dedicated to the project with some impacts and today, it's difficult to give you in terms of this. Of course, I could just tell you it's postponed by three months, which I just said. Maybe we need to reassess the situation where we'll be back to a normal situation in the Gulf region. Thank you. The next question is from Henri Patricot, UBS. Mr. Patricot, we cannot hear you. Maybe line is on mute. The next question is from Jason Gabelman, TD Cowen. Hey, good afternoon. Thanks for taking my questions. I wanted to ask the first one on the potential for windfall taxes, given the recent backup in commodity prices, I'm wondering, Patrick, if your conversations with governments indicate any appetite to reinstitute windfall taxes. Honestly, until now. In fact, most of the governments have taken some measures in between 2010 and 2015, which are still there in many of our countries. We had one impact, limited, an impact now in Brazil, where we have instated an export tax for four months. There are today rumors that they could extend it, which has been declared as not constitutional, it seems to be a legal fight around this export tax in Brazil. The U.K. scheme has been increased recent years, they cannot take more. Norwegian is okay. Honestly, in most of our PSCs, the reality is that there are some mechanism which you can observe when you look to the average tax rate of TotalEnergies between an environment at $60 per barrel or $50 per barrel where we are more or less an average of 40%, and an environment at $90 per barrel or $80 per barrel, we are more around the 45%- 50%. There are some mechanism within the PSC. In fact, when the price is going up, the governments are taking a bigger stake. In fact, it's no more because in fact, the way we negotiate ourselves, we try to protect the low cycle by giving up a little more on the high cycle. That's a balance that we try to institute, to propose to the government. This mechanism exists, we didn't face this type of conversation, to be honest, since the beginning of the crisis. We are not there, and that's what I can tell you. Except Brazil, I don't have today in my head any other situation where we have some discussion. Again, because the mechanism exists already in many of our PSC. Great. Thanks for that. My follow-up is, I wanted to go back to the Yamal project for a minute and just understand, because you have kind of the interest in the liquefaction facility, and then you're separately lifting volumes as well. I'm trying to understand kind of what the cash flow split is between those two parts of the business and also if you've been able to actually get cash distributions out of the Yamal facility itself over the past few years. In fact, you are perfectly true. There are two different activities. One is a Russian activity, Russian in Russia, which is a Yamal liquefaction plant, where we are a shareholder for 20%. Some cash flows has been distributed. It's not an easy way to, because when we respect sanctions, the question is it distributed in Russia and when does it flow to Europe? Again, the sanctions in Europe have limited the number of capacity to transfer from Russia to Europe. Some cash has come back to TotalEnergies, not the full of that. This part is not, I can tell you. In fact, in the way we plan, we don't consider that. We just are cautious. It's not coming on a regular basis. In fact, it's some time- to- time, we have some opening, but that's not a regular basis. Some cash is somewhere, I would say, in Russia, expect waiting for us. We have the other part, The European listing. Yes, there's this one. It's out of Russia. It's a business where it's our U.K. and Swiss entity, or U.K. entity, I think, which is dealing with Russian contracts, on which the cash is out. This one, of course, we have a direct access to the cash. The magnitude of this business is around, I would say, an average of $400 million. Again, it's going up and down depending on the different. Because the contracts are linked to the Brent, so it depends on the assumptions that you will take on the Brent. Let's say $300 million-$400 million per year. Yeah, that's a potential site. It's a contract as part of the portfolio. It's not a major situation for TotalEnergies. Great. Thanks for the answers. The next question is from Henri Patricot of UBS. Yes. Hello, thank you for the update. Just one question. Coming back to capital allocation. Last quarter, you mentioned that you were evaluating options to accelerate short cycle investments in upstream. Where are you on these options? It sound like that you might typically CapEx on chains. Are they just not being considered anymore? Thank you. No, we have, of course, the different subsidiaries have worked on it. There have been some proposals. We have approved some few, I think around $300 million this year. The guidance of $15 billion, maybe it's good at the end, $15.2 billion, which I consider is part of the global guidance. That's not a real impact. This might have for next year, there is a little more because, of course, these type of actions are not only for immediate actions. I would say you have probably $500 million of capital allocation acceleration, which would come next year. The global guidance we gave you last year, which was, I think, around $ 15 billion-$17 billion per year of CapEx. We said, $ 14 billion-$16 billion. We'll stay around in the $ 15 billion-$16 billion, I would say, range. Yes, we have taken some actions, but will impact a little more 2027 than 2026. Thank you. The next question is from Bertrand Hodée, Kepler Cheuvreux. Yes. Thank you for taking my question. Wanted to come back and to try to quantify the underperformance of the LNG trading in Q2. Integrated LNG net income was down $500 million, Q2. While at the same time, contribution from equity affiliate, which is my understanding, mainly liquefaction, was up $300 million. That puts a Q -on- Q discrepancy at group level for integrated LNG, excluding affiliate, at around $800 million. This is what we should understand as a swing in the- Yeah trading performance? You are very good, Bertrand. We can add nothing to you. We are very transparent. We mentioned to you that there was underperformance last quarter of around $500 million, and your $800 million. You have underperformance, reversed not only from $500 million, but to less than $300 million compared to a normal situation. You merit a certain distinction. The second question, probably on your comment that those long position that did not work out in Q2 was now being in positive territory. Is that a hint that we could be headed for underperformance- Exactly of LNG trading in Q2? Yeah. Exactly. In Q3, by the same magnitude? Exactly. Maybe we are only in July. We are in July. Maybe it could be larger, I don't know. Now, be clear. Yes, it could be the same magnitude. Be clear. These markets, when they are volatile, they are volatile. When you take $5 per MMBtu in 20 or 30 days, 20 days, I can tell you, these type of positions are making [inaudible]. The question will be not only what the results are not finished on July 22nd, but on September 30. We'll come back, but it's possible, yes. We might come back to you with the good news of the same magnitude. I hope so. Thank you. Thank you for your support. The next question is from Fergus Neve, Rothschild & Co Redburn. Yeah. Hi there. Thank you very much for taking my questions. Just on the LNG growth pipeline, it was positive to see the ECA LNG project start up earlier this month. Could you provide a quick update of where the FID for Papua LNG stands today, and also how the Mozambique project is progressing? Secondly, just on the refining environment, I was wondering if you could comment at all on how your margin has looked so far in July. Thanks. In July, it looks very well. I can tell you, the average margin on the last 30 days were at $31 per barrel. It looked very well, I think July is probably around $35 per barrel. It reached an historic record for me, which were more than $40 per barrel-$ 44 per barrel I've seen one day. Today it's a little backtracking because, again, the crude oil is going up. In fact, I have one observation to make here since the Strait of Hormuz was again blocked since July 9. When you make the sum of crude oil and refining margin, we are almost at $130 per barrel day- after- day. I don't know if there is a trick, but probably. That's what I mentioned that in my opening comments. The second one, the first one on Papua LNG, we are working all together very closely with ExxonMobil, with Santos, with the government, of course. The government has just launched the last part of the procedures, the local hearings. The objective is to clearly to sanction all that before year-end. November, I think, is the target. We are aligning the interest of all the partner in the interest of the projects, we are studying how we can maximize synergies today between Papua PNG, LNG, in order to deliver the most efficient project to the government. Again, in close cooperation with the government. I'm happy to see that the different stakeholders have all the same objectives today and, okay, we need to put together some few. It's not an easy one, but I'm optimistic we could reach this sanction. We are all working for that, and we are very aligned on that. On Mozambique LNG project. Okay, it has restarted, as you know, since January, and today we are, in fact, increasing the mobilization of people on the ground. I think we are at 7,000 or 8,000 people. Project is progressing. Let's be clear. We are facing some few difficulties because some of the equipment were, in fact, being built in Dubai and the different yards in the Middle East. We had to face some tough times to exit all this equipment. I think it's done now. The progress, we are progressing. And in fact, today, when we compare to the progress here, we are almost at 45% of completion. Net, we have still a lot of things to build on the, I would say, there in Afungi and offshore. That's on its way, with the target being 2029 for the first train, and we work on it. Brilliant. Thank you very much. The next question is from Jean-Luc Romain, CIC- CIB. Thank you for taking my question. It relates to refining and your plan to introduce more green hydrogen in your system. Where are you with this, and are there regulations in Europe which are not going fast enough for you to progress on that? Yes, the French one. No, we are working on it. No, where are we? In fact, we have nice offers. The good news of the quarter is that the German parliament has adopted its own regulation. Today we are very clear on the German part and positively part. Leuna will be able to maximize the use of green hydrogen. That's the good news. There was a bad news on the Netherlands part, which has been adopted, but not in the maximum part. I think Zeeland Refinery will be able to take 30%, more or less, of what we are planning to take. Again, if there is no fiscal support, we cannot do that. Then we are working today with the last two governments, which is a Belgian one, where the draft are not so positive, and the French ones, where the drafts are positive. The problem with the French system is that you need to go to the parliament and to make fiscal reforms in the French parliament is not an easy task for the government. We are working on it, and I think we'd like to have the definitive scheme and not an interim one, to be honest. Of course, if we commit for long-term contracts of 10- 15 years, we need to have a scheme which will give us some, I would say, certain level of comfort. It's a very technical matters, to be honest. It's one of the most complex topic I know. To explain to a political leader the RED III and what it is to make a green hydrogen in Europe, getting some support, this one is tough, to be honest. We have some momentum, we are working on that. Not only ourselves, by the way, in France, of course, we are working hand in hand with Air Liquide, which is also interested to get these regulations. Progressing, but still, again, for us to commit on long-term contracts, we need to have all these regulation being enacted. It's the beauty of Europe. You think you've done the work because there is a directive in Brussels, then you take four years to implement it in each country. By the way, where I'm afraid that I just discovered that there is a new directive which could, again, come back to the definition of green hydrogen, the RED IV, by some consultation. To be honest, when you read that, you begin to be afraid because it's a problem already is coming from regulation, so it could be difficult. Okay? Thank you very much. The last question is from Ben Fallon, ODDO BHF. Hi, Patrick, and thank you for taking my question. In the light of the recent escalation in the Middle East, has your view on geopolitical risk changed? Which region do you see as offering the most attractive risk-adjusted investment opportunities of the coming years, and how might this influence your future capital allocation priorities? I know it's maybe for the CMD, but I think it's important. Thank you. Yeah, thank you, Ben. We continue to consider the Middle East as an investable region. There is no doubt about it. It's a question, of course, at the end of the day, it's a question of risk and reward. Maybe the reward will be to have a little higher. When I saw my U.S. competitors rushing to Iraq during the last weekend, if I notice the number of MOU signed to develop hundreds of thousands of barrels, I don't know why these U.S. companies suddenly would like to see lower geopolitical risk and ourselves, which have more, I would say, DNA in the region, would consider it as a higher one. We think it's a question of risk and reward. It's always policy. Again, it's back also to my comments about having alternative routes to export the oil to go to the market. Having said that, it's clear as well that the policy and strategy of TotalEnergies has been to diversify the portfolio, and that reinforce my strong belief diversification is of essence in this business. We have done it well, in Brazil, in Africa, in new countries in Africa. Of course, the U.S. are also attractive to us, but we are building quite a big position in the U.S. in terms of capital allocation for LNG and for integrated power, so we are fine. I understand the question, but at the end, when you make oil and gas, you go where you find it. If we discover oil and gas in Suriname and in Namibia, we are happy. That's true that we don't find oil and gas in Europe to answer to your questions. By the way, we don't have the right to look for it. That's where we are. For me, the answer to your question is fundamentally to maintain our strategy of diversification. This is what we will present you in September. I think the events that we have faced in the last four months have demonstrated that this is the right one, and we have been able, as I answer, to supply feedstock to pickers or not to claim any force majeure for our LNG customers, contrary to some competitors, because we have a diversified source of supply of LNG and from this perspective, building a position in Mozambique. Look to the countries we are developing in the last three years, Suriname, Malaysia, Namibia. We are continuing to diversify our stakes because that's the reality of our business. It's not only in 2026 that we discover that. It has been the case for companies 102 years old, I think it has been the case for long. That's what I would answer to your question. Gentlemen, that was the last question. I turn the conference back to you for any closing remarks. Yeah. Thank you for your attendance today and for your support. I remind all of you that we have a Capital Market Day in New York City on the 28th of September. I think it is a Monday, if I remember right. Monday 28th of September, be all ready to attend the TotalEnergies Capital Market Day. With more news to come because we continue to work during summertime. Thank you for your attendance and happy holidays to all of you. Ladies and gentlemen, this concludes the conference call. Thank you all for your participation. You may now disconnect.