Prepared remarks
Hello, everybody. Good afternoon or good morning for those who are in the U.S. And before Jean-Pierre will go through the details of the second quarter financials, I would like first to make a 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 clearly impacting our markets and our operations and our perspectives. Although we were all hoping in mid-June that the resolution could be envisaged for 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 almost 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 to 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. But 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 have widened, while refining, petrochemicals, biofuel margins, but also distribution margins were increased with some even reaching historic levels. And 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. But 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 of crude oil around $95 per barrel, and margins at $35 per barrel. E&P delivered a strong quarter in terms of production, thanks to a solid 4% organic growth, higher than our forecast, coming from our rich and diversified portfolio of projects, which was planned in particular from Brazil, the U.S., and Libya. And I must say it's very good from a strong operational performance, limiting, I would say, the unexpected stoppage of the production. So it was a very good performance from an operational point of view. And all that allowed 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 operations despite, as well, I would say, there was a disturbance 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 production was going up quite quickly, and we had limitations, I would say, only 5% of our global production. But this weekend after the conflict came back, we were more back to 8%, 10% of limitations. So difficult, I think we see 5% to 10% in our perspective. It will obviously depend on the way that the conflict will develop. And again, it's not only production for us also lifting offloading the crude oil, which might be affected. And 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. So 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. Our 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. And also by doing that, contributing to security of supply of France and Europe. This performance was achieved. Also, some of our facilities have been impacted by events outside of our control like the SATORP refinery in Jubail, Saudi Arabia, which was hit in mid-April, if I remember well, by some drones and which is back today at around 70% of capacity, with full capacity expected by the end of the third quarter. But also Port Arthur in the U.S. suffered unfortunately in June from a lightning strike during the 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 the top of our usual performance of $500 million. And last but not least, on the downstream, Marketing & Services has reported the best ever quarter driven by the positive impact of the seasonality in Europe, but also higher, I would say, unit 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 5-year average. But these factors did not materialize during the second quarter, even in fact, prices have declined through the quarter, leading to, I would say, weaker or poor results on the trading business. The story is not over. As you have probably seen now gas price in Europe have rallied. 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 since 2024, even in the absence of farm downs during this quarter. But it was supported by the closing of the transaction with EPH in April, 1 month earlier or 1 to 2 months earlier than expected. And the cash flow coming from EPH was as per the expectations. So the strong deliveries on almost all fronts, but I would say, 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 have deleveraged down to a gearing ratio of 13%, which shows 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. And 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 in the second quarter. And 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 the second quarter financial results.
Thank you, Patrick. So I will start by commenting on the price environment in the second quarter '26 versus the first quarter. We captured 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 differentials and a lifting schedule weighted towards the end of the quarter in the 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 MMBtu and our average LNG price increased by 20% at $10.2 per MMBtu. Oil prices started to impact LNG prices with 1 to 2 months of lag effects according to LNG pricing formulas. Finally, the European refining margins increased by $13.5 per barrel on average over the quarter. In this price environment, the company reported very strong financial results, increasing by almost 15% compared to the first quarter with second quarter '26 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. And 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 these very strong results, the highest since the end of '22, despite 2 challenges. Although 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 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 for the quarter as explained by Patrick. TotalEnergies has delivered strong profitability this quarter with return on equity at 15.9% and 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 '26, benefiting from the ramp-up of the projects started since the beginning of '25 and from improved operational facility availability. The impact of the conflict in the Middle East is around 210,000 barrels of oil equivalent per day over the quarter, below the guidance communicated last quarter of 360,000 barrels due to the company's production ramp-up in the 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 barrels of oil equivalent per day. Looking forward, we expect to maintain a strong momentum with oil and gas production as in the first quarter, excluding the Middle East impact, expected to grow around 3% compared to the third quarter of '25 in line with the annual growth guidance. Turning to the quarterly results and starting with E&P, the segment 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 and demonstrating the accretive new projects 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 maintained 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 shut-in production in Qatar related to the Middle East conflict. In contrast to the outperformance in the first quarter, this quarter, the second quarter was impacted by the underperformance of gas trading activities in an overall flat or even bearish European market, 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 effect on pricing formula, the company anticipates an average LNG selling price of above $11.5 per MMBtu for the third quarter of '26. As we execute our consistent strategy in LNG, the main milestone of the quarter was the startup of Energía 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 shifted it to the Asian market where the company pursued its strategy of signing long-term oil index LNG contracts with new clients in China or in Japan. Turning now to Integrated Power. Net power generation increased to 14.8 terawatt-hour, 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 terawatt-hour increase in production from flexible gas-fired capacity resulting notably from the completion of the transaction with EPH end of April. TotalEnergies is on track to reach its annual objective in integrated power, in particular to generate more than 60 terawatt-hours 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. And 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 sales 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 started contributing in the second quarter, we said in the first quarter that integrated power should benefit in 2026 from 10 terawatt-hour of net power production, in line with the 15 terawatt-hour 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 capital. The working capital decreased by $1.2 billion during the second quarter, largely driven by the reversal of the first quarter buildup 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 '26 net investment level of $15 billion. As a result, the gearing has 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.
Questions and answers
The first question is from Martijn Rats, Morgan Stanley.
Two questions, if I may. I know there's an awful lot of attention, of course, on the Middle East, but I wanted to ask you a quick one about Namibia. It's still very important for Total. Where do you stand on, sort of, 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. And then secondly, I wanted to ask you about the payout ratio for this year because the guidance was more than 40%. I think we're sort of tracking below that so far. Of course, you see volatile macro environment is perhaps no surprise. But the, sort of, the payout guidance, over which period should we expect that to be realized? Would you still expect to have more than 40% payout sort of over the year? Or should that become a longer-term target?
Thank you, Martijn, for the first question. To be precise, on the Galp transaction related to Mopane and Venus, late last week we received the official approval from the Ministry of Energy of Namibia. We are finalizing the remaining paperwork to close the deal, potentially tonight or tomorrow. Your question came at the right time. This is important because being operator on both developments has strong value for us as we approach the first FID. Regarding the FID for Venus, there are intense discussions. The government of Namibia and the consortium have a joint target to sanction it by the end of July. Discussions are progressing; we will see if we can conclude in July or if more time is needed. Technically, we have selected all contractors and are ready to take the FID, subject to final discussions with the government. Progress has been made, but some issues remain. I am reasonably optimistic: all parties share a clear joint interest, and Namibian authorities are supportive of having a strong operator that can capitalize on synergies between the projects. Now that Mopane approval is complete and the deal will close, the next step is appraisal in the second half. We have three wells planned in 2027 and expect FID in 2028. This puts us in strong momentum. Namibia is becoming and will be a very important hub for our future growth both to 2030 and beyond. On other topics, we are targeting a 40% payout. We increased buybacks and dividends between Q1 and Q2. I cannot say exactly where we will end up. We were somewhat cautious when we increased the buyback from $750 million to $1.5 billion and have maintained the $1.5 billion for the next quarter. The rapid drop in crude oil prices to around $70 per barrel after the MOU in June surprised us, so it is difficult to predict second-half cash flow. Overall, we expect to be above the guidance we gave. At the end of April I cited cash flow guidance based on $80 per barrel and a $7 per barrel refining margin, implying about $32 billion. We will clearly be above that. Whether it lands around $35 billion or $40 billion, I do not know. If cash flow ends up at $35 billion, that implies roughly an additional $1 billion available to return to shareholders in the last quarter. How to execute that will be debated by the Board. My point is this is a positive situation because we are generating more cash flow than the guidance we gave in February. The 40% payout target refers to an annual basis. Last year we were around 50 to 55 percent, so on a multi-year view we are already ahead of 40 percent. Again, the 40% guidance is guidance for the Board. The Board is also, as I explained last quarter, considering the gearing ratio. Reducing gearing to around 10% is an objective and we might achieve it this year. That is the balancing equation for capital distribution the Board will consider, and I believe we will manage it as we have in the past while respecting our stakeholders.
The next question is from Michele Della Vigna, Goldman Sachs.
I wanted to ask 2 questions. The first one is if you have an update on the 2 giant oil developments you're operating in Uganda and Suriname? The second one is more of a macro question. I was wondering if you had a view on China demand. We've seen a drop of about 5 million barrels per day in import since the beginning of the conflict. It's very difficult to unpick what is destocking, demand substitution, demand destruction? I was just wondering if you had any view of how to think about it.
Okay. First question: on Uganda, we are in the last six months of development and expect crude oil production to start before the end of the year. I would say 2027 will be the year when we reach the plateau. We have two developments: Tilenga on one side and the offshore Kingfisher, which I think is ready to start up by September. If my information is correct, the pipeline should also be ready by September. So we might start production next quarter at a rate of around 60,000 barrels per day from Kingfisher, and then Tilenga will ramp up in the first half of 2027. So full plateau for me is by mid-2027. We will follow that carefully. Of course, Uganda is affected today by Ebola. If it stops, we might organize a field trip with some of you who are brave enough to go to Uganda in September 2027. For now, Uganda is a matter of finalizing and turning the wells on. On Suriname, things are moving very well. We confirm that production will start in the first half of 2028 according to our plan. Construction has already progressed by 40 percent; the FPSO is being built correctly in the yard. This is more classical. It is more complex to execute an onshore project than an offshore one. In Suriname we are in a deepwater project for TotalEnergies and we know how to execute them. China is very interesting on the demand side. We were all surprised by the May and June statistics showing refinery runs down from 15.5 million barrels per day in February to 12.5 million barrels per day in June. The Chinese authorities decided quickly to stop exporting products and reduced refinery run rates by about 10 percent to roughly 90 percent, which affected exports more than domestic demand. It is difficult to say there was a domestic demand disruption. We have observed some turnarounds on Chinese refineries in July and August, so we do not expect much increase in demand from China. When you look at the system in China, it has quite an impact on the oil market. In April we commented that a Strait of Hormuz blockade would represent 10 to 12 million barrels per day of market disruption; the Chinese policy has effectively removed about 4 million barrels per day. Add that the U.S. released almost 2 million barrels per day from the SPR, and those two actions solved almost 60 percent of the problem. That is probably why oil went up to $120 but not much higher. For the coming months, you can observe with me that we are back to the blockade today: no vessels or tankers are crossing the Strait at all. The Chinese announced they would allow some refineries to export a few products during the quiet period at Hormuz; today, with these events, that might not be the case again. So my comment is: fewer exports, and whether there is a domestic demand disruption is difficult to determine from the available data.
The next question is from Biraj Borkhataria, RBC.
Just 2 on your LNG business. In June, there were reports around Russian decree to authorize the sale of 10% of Arctic LNG 2, I think, related to the European sanctions. So I don't believe you have commented, but are you aware and are you planning to exit there? And 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 at the full-year results, and it wasn't quite clear exactly what it would mean and there's been some conflicting reports. So any color there would be helpful.
Thank you, Biraj, for your questions. I know that you have specific interest for Russian matters for good reasons, by the way. So 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 31, 2022, shortly after the war. We recorded an impairment of $4.1 billion, which was, in fact, concerning notably Arctic LNG 2, full write-off. Secondly, that Arctic LNG 2 has been placed under sanctions by U.S. authority on the 2nd of November '23. And as a result, immediately, we suspended procedures in accordance with existing contracts. And in consequence, in fact, our rights and obligations under these contracts related to Arctic LNG 2 have been suspended since November '23. In such a context, Novatek approached us, indeed, and initiated discussions for the transfer of our 10% in Arctic LNG 2 to one of their own subsidiaries, Nordline. And 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 in the joint interest of TotalEnergies and Novatek to dispose of our Arctic LNG 2 shares, which again were fully impaired in '22. 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 you, but we are waiting to see what is the legal language precisely. So as you have seen, there was some press news this morning that there was intense discussion about the new sanctions package at Brussels. And 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. So that's the case. And it says that there is a legal language, but again, which could, in fact, have an impact on Yamal LNG, according to what we've heard. 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. So a specific case. So it's a little complex story. But that might have, yes, an impact on, in fact, if it is the case, that means that TotalEnergies could not use a force majeure to say like it was until now because until now, we could, in fact, with the regulations which were in place, which were banning the LNG exports to the EU, but there was a question mark. I made that comment, I think, in April to all of you or in February, I remember that we were questioning whether there was a different interpretation of the European sanctions, but that even an EU company could not purchase any of Russian LNG either for EU or outside of EU. So it seems that the new language could, in fact, clarify it in a way that it could be done outside of the EU if we use some EU LNG tankers in fact. Which, in fact, would mean that the interest of EU companies would be somehow preserved independently of this, if it's outside of the EU. So 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, and 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. But My comment is that if that is the case, again, I think the interest of EU companies will be preserved because honestly, to let the 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. So let's see. That's what I can tell you. And we'll keep you aware, obviously, because it has some impact on our own business. And we'll keep you aware of the situation.
The next question is from Doug Leggate of Wolfe Research.
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 to be honest, the hybrid bond, for me, is a debt. It's a debt, but it's not a debt. It's quasi-debt with a low interest rate compared to what we can issue on 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 at a 3% coupon, so it's quite a cheap debt. Is it a priority to unwind all that? My answer is clear: no. We have made some partial reimbursement, but it's not a priority. As CEO, I'm more focused on the overall cost of our different bonds rather than any specific one. Maybe Jean-Pierre will add something.
It's highly dependent on the market. So if you could consider it cheap debt, there is no reason not to keep the hybrids in our portfolio. But of course, it's highly dependent on the conditions as Patrick explained, what is important for us is, globally the cost of global debt, senior bonds plus hybrids.
Yes. My follow-up, Patrick, is very specific on exploration. So you hired Nicola out of Eni and you have Mopane and Venus in Namibia. Back in 2016, Total drilled the only deepwater well in Uruguay. And Eni, late last year farmed into Uruguay. It seems that activity there is picking up a bit. So my question is, when you roll all that together, does Total have any ambitions to move into Uruguay?
Okay. I mean, Doug, you will need to ask a question to Nicola. To be honest, Nicola did not come to my office to tell me, we need absolutely to come back to Uruguay, so to be clear. Our own experience in Uruguay has been quite average, to be honest. And 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. So we made 2 drillings in this deepwater basin, which was honestly not very encouraging. So 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 discoveries. So he has some other ideas or other African countries. But 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. And I told him it's up to you to decide where we'll put the money. You have to share with you your convictions. But if it's your idea, we know we follow that. By the way, when I was looking to potentially not buy it down, but the Venus case, looking to the department, Venus development might generate quite a nice cash flow paying many years of like Suriname, the GranMorgu development will pay many years of exploration. So that we need to keep in mind, but it's in terms of cash generation of added value, exploration for me is a good nice engine. But again, I trust Nicola that he will bring to us ideas. I don't know if it's Uruguay or not. But until now, it's not Uruguay.
The next question is from Christopher Kuplent, Bank of America.
Just 2 quick questions for me, Patrick. The info that you've given us on the positioning of your gas traders is very helpful. Can you maybe comment on whether their bullishness has extended into power and your merchant and spark spread position there? And what you expect on that side now that you've got access to the EPH portfolio? And the second question, as ever, I keep trying to get comments out of you on the state of the M&A market. But 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.
I commented on gas trading earlier; gas trading has again shown weaker trading performance. I would say our current position is a winning one. On electricity, I honestly don't have much visibility. As you know, the EPH deal involves buying the assets but converting them to tolling arrangements to have access to the electrons and trade the electricity ourselves. At this stage, not all the tolling agreements have been signed yet. We are working on it. I think the full trading potential from the EPH deal is more likely to materialize in the fourth quarter rather than immediately. We expect some additional value and we have set objectives, which we discussed with our electricity trading team last week during our five-year business plan, and we expect them to deliver. We trade on two markets: Europe and the U.S. The U.S. is a bit more complex because our position there is still limited. We will need to increase our U.S. position if we want to be profitable trading electricity in that market. In Europe we have a fairly large portfolio across several countries and have project expectations. The U.S. is still work in progress. Regarding the M&A market, I haven't had time to analyze the price Vår Energi paid to acquire BlueNord Energy. I will probably receive a memo; I have been occupied the last few days. It seems to me the market today is more of a seller's market than a buyer's market given today's crude oil price. If you make a deal, unless there is an earn-out or other scheme to capture potential upside, it's not a stable market. Before the crisis, you could imagine deals where buyers paid around $70 per barrel. Today, sellers would be looking to sell at $70. Personally, I'm not a seller of these assets today because we don't want to give up upside. So selling is probably more attractive than buying right now. I cannot comment on the specific situation you mentioned. Maybe we have some preemption rights; I don't know the situation, obviously, so we'll look at it. The assets are ours and we operate them. I'm not surprised because BlueNord was owned by a fund and when I met the owner in Denmark a few months ago it was clear they were willing to sell. For TotalEnergies, we already have a significant share in the Danish underground assets, which are quite mature. I think we are fine with what we have, but we'll look into the situation.
The next question is from Mark Wilson, Jefferies.
Regarding European projects, could I ask about the Cyprus project, Cronos Block 6 and what the expectations to move that one forward are, please? And then secondly, on gas trading, yes, I agree with others helpful comments, but 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 made material moves up and down and probably that enables that business. But should we think of your gas trading business as being a more European regional focused one?
No, it's still not entirely clear cut. We are a global gas trading business and a significant LNG player, with exposure to different markets in the U.S., Asia and Europe. The main miss was on our European anticipation for the TTF. At the start of the year prices were in the mid-teens and by the end of March around $17. Our teams expected prices could rise toward $19–$20 by July, anticipating the impact of the Qatari production disruption and the need to rebuild European inventories. The market, however, probably judged it was too early to price in that rise, partly because the Qatari disruption was expected to stop (it did in June but returned in July) and because European inventories could be rebuilt over time. Weather in Europe was also quite mild in the second quarter, which reduced demand. So the only real underperformance we saw was on our European position; we did not see similar underperformance in other markets. On Cronos, thank you for the question. We are working toward FIDs, aiming to finalize them at the end of July. I must acknowledge Eni, the operator, with whom we jointly progressed over the last six months. We are working hard to finalize the FID, similar to what we did on Venus. Cronos is an attractive development: it produces gas in Cyprus and leverages existing infrastructure to limit CapEx, with subsea tie-back to the Zohr facilities in Egypt for gas treatment and then to the Damietta LNG plant. That required intergovernmental and third-party agreements to use those installations, and those arrangements are being completed. We expect to be able to announce the outcome soon, probably next week. For TotalEnergies, Cronos would provide access to about 1.4 million tonnes of LNG in Egypt, well positioned for the European market. It is also the first gas development in Cyprus and could open the door to further value creation there. It has been a long journey, but we are close and would be happy to invest capital in the Cronos project.
The next question is from Matt Lofting at JPMorgan.
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. So if we were to stick to the sort of the $80, $15 gas, and $7 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 3 months ago? And 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? And is there a scenario where additional measures could be required from that perspective, particularly if conflict in the Middle East persists?
Okay. On the first question, that’s fairly straightforward. The previous $32 billion estimate, given the improvement in the second quarter, would be raised to about $34.5 billion. That’s why I said $35 billion in response to your colleague. So $34 billion to $35 billion would be a reasonable guidance in that environment. If we look at oil prices, since the beginning of the year we’ve averaged around $90.7, while the last 30 days have averaged about $76, so there’s quite a spread — roughly between $75 and $90. In our assumptions we have $40 billion and $34.5 billion scenarios. The current forward curve is a moving target and follows the spot, so I don’t have exact forward figures today. I mentioned a range of about $35 billion to $38–39 billion if the second half mirrors the first half. If you double the first half you end up around $38 billion. That would reflect a higher environment — oil at about $90, a refining margin of $15, and TTF at $15, which was the first-half average. If that environment is replicated, we could deliver around $38 billion instead of $35 billion. You therefore have a range of outcomes; it might be lower at year end, but that’s what I can tell you today. On the second question, no — we have no problem supplying feedstock to our refining system. We are producing a lot of oil in Brazil and Africa. Atlantic-basin or European refineries are generally supplied by Atlantic-basin crude. While we do like some sour crude from the Middle East to produce more diesel — it’s the best for diesel — the volume is limited and Middle Eastern sour crude tends to go more to Asian refineries than to European ones. So we have no concerns about feeding our refining system. The only area of concern is SATORP in Saudi Arabia. It was hit, and I hope it won’t be hit again, but it is not operating at full capacity. SATORP’s production is effectively stranded in the Gulf and was used within the Saudi system during the second quarter for domestic needs because other refineries were affected. From that perspective we are running it for the domestic market, and we’ll monitor what could happen if the situation intensifies. But overall, we do not have a security-of-supply issue for feedstock or our refining system.
The next question is from Lucas Hermann, BNP Paribas.
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 of fracturing within OPEC. The UAE having departed, Iraq talking about an incremental quota or changing its quota. As you think forward 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? And secondly, if I might, and maybe this is just one that I should leave or we should leave for the strategy day, simply to ask whether in light of the actions you've taken on Mopane around Mopane, the addition of EPH and the environment we're seeing in refining, in particular, at the moment, but may be sustained, whether that's changed and altered your target of $20 billion or so of free cash by 2030 in the $70 world?
Okay. The first question is a good one for the investor presentation outlook in September, where we will speak more about strategy. In terms of capital discipline, and given everything you described, it is very important to stick to that discipline and to test all our projects at $50 per barrel. Yes, you can infer that today we are in a world of high prices, but we could move to a situation where everyone wants to produce more, and then countries like Saudi Arabia could change policy again as they did in 2020. If everyone increases production, prices could come down. When Saudi Arabia decided to close the market in 2020, a few players around them quickly returned to more discipline. It is a matter of discipline, and for us we continue to test projects at $50. We planned our five-year business plan at $60 and we also test scenarios at $70 or $80, but we will keep discipline because this is a cyclical industry. You should not be surprised that when we speak at the end of September about capital investments, the figures will be in line with what we told you last year. We will not suddenly increase our CapEx because of a short-term higher price environment. Does this change 2030? Not really. Mopane’s production is beyond 2030 and Venus should start by the end of 2030. For me, Venus and Mopane are 2030 to 2035, and we are working on that, so there is no impact on our planning. EPH was already part of our long-term five-year plan. What we anticipated with EPH involved reallocating some CapEx to M&A in integrated power. That has been done, and in fact the deal was modeled in our future cash flows to 2030. On refining, I will not take the current balance for granted. Having managed that business for three years, I am cautious. Right now both crude and product markets are positive for refiners: products are being supported by reduced flows through the Strait of Hormuz and by the Russian situation, which has reduced diesel exports, all of which push product prices up. If the Strait of Hormuz becomes intermittently closed and reopened as some authorities suggest might be the new normal, then we will not be in a typical $50 per barrel cycle. We are discussing and building some pipeline projects to bypass the Strait of Hormuz, but those will take a few years. So I do not assume the current refining balance will hold through 2030. We will come back to that question more precisely. Since we met last September, we have confirmed our targets and we will come back to you to explain them fully. Yes, the increase in free cash generation we announced, which was more than $10 billion, will be confirmed. That is one of the first messages we will deliver in September. The second message will give more color on beyond 2030, because we are now working past 2030. The company has two objectives: to deliver all the additional free cash by 2030 and to continue the growth story beyond 2030. We are confident and we are working on the projects that will sustain TotalEnergies’ growth after 2030.
The next question is Nash Cui, Barclays.
Two, please. The first one is on the Middle East. Patrick, we watch some of your recent interviews with French media. I think you talked 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 Total's longer-term strategy in that area, please? And then the second question is on power, 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?
On the Middle East, it is clear to me that we are very well positioned in Abu Dhabi. We have announced two very large projects and, despite the conflict in the region, we have been active in Abu Dhabi to strengthen TotalEnergies’ partnership and position with ADNOC, XRG and Masdar. We announced a joint venture with Masdar across renewable businesses in Asia and the Bab Gas Cap concession, which was a long-standing ambition for many in the company. When we signed the onshore Bab concession in 2015 some were skeptical, but ten years later we have delivered additional value because we stayed in the place with our partners and worked alongside ADNOC. I would like to thank the Emirati authorities for the trust they have placed in the existing consortium. We have also announced the Umm Shaif Gas Cap and reached FID this week. We hold a 20% share of the Umm Shaif Gas Cap, which includes not only gas but also significant condensates and liquids. When you have liquids you need outlets, so it is clear Abu Dhabi has been very active and ADNOC is moving quickly. We need to double the pipeline to Fujairah not only to accommodate future growth but also to tie in offshore production. ADNOC is inviting partners to consider these projects and we are taking that invitation very seriously. Iraq is another area of interest because we have production there. Today Iraq effectively has one main export route through Basra and the Strait of Hormuz, so it is important to diversify exit routes. Projects are being studied from Iraq to Syria and TotalEnergies is keen to participate or develop opportunities where possible. If we want to continue investing because oil is relatively cheap and plentiful, we must diversify export routes or we will not have a sound business case. This is important for the countries themselves too. Even if conflicts were resolved quickly, it remains essential to pursue alternative routes for oil. On integrated power, our next ambition is to achieve the 2030 target. This year we will reach about 60 terawatt hours and by 2030 we expect more than 100 terawatt hours, with 100 terawatt hours likely a conservative estimate. More importantly, we want the business to generate net cash flow. I expect it to be net cash flow positive next year. This year it might be, but I prefer to see it in a normal CapEx environment. Our goal is for integrated power to contribute to our broader free cash flow objective of more than $10 billion by 2030, with approximately $2 billion coming from integrated power. Beyond 2030 there are different options for growth and the pace will depend on opportunities. The Board is focused on the company’s ability to deliver targets and create value rather than just setting ambitious plans. Investors have become more supportive of our investments, and I believe we are right to invest because electrification is a central trend globally. It is not just about being green, it is about electrification, domestic energy resources, and demand driven by data centers and AI. Investing in electricity complements our oil and gas activities, and the gas-to-power connection is obvious. Our ambition is to continue developing the integrated model—where gas, renewables, customers and trading come together—in geographies where that model is feasible. That will include a few major European countries, the United States, and if you add Brazil and India, you have the core markets where we can deliver integration and profitability. Our next ambition is to be stronger in those markets where we can execute the integrated model and create value.
The next question is from Kim Fustier, HSBC.
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? So 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? And then 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? And 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?
Okay, thank you. Beginning of July, until July 8 when the blockade returned, production was rising and the impact on our production was only around 5%. Our global production from the Middle East — if you consider our base was around 650,000 barrels per day — was by that time about 550,000 barrels per day because there was increased output from many assets. In particular, Abu Dhabi assets were almost back to normal production, which shows wells in the Middle East can be reopened and brought back quickly. Qatar was not fully back on the LNG side because of cautious ramping up, and Ratawi in Iraq was back to roughly half of its production. So we were minimizing losses and ramping up quickly to return to normal levels. Since July 8, with the renewed situation, the impact is more around 8% to 9% as I mentioned earlier, because we cannot maintain production if we cannot offtake. This is a matter of offtake and logistics: when you produce at maximum, tanks fill up and logistics constrain production. The Qatargas 2 LNG plant, which had been ramping up, has been shut down again, so that also has an impact. To be clear on guidance, if we were in second-quarter conditions production could see a 10% impact, but physical offtake could be higher. Our initial guidance of 15% was in terms of physical offtake during the second quarter; the third quarter could be similar. The good news is that if the Strait of Hormuz reopens, we can ramp up quickly because tankers can return and offtake can resume. During the few weeks when things were open we managed to load three tankers, but now offtake is back to nil. On Ratawi, Phase 1 was delayed. Ratawi cannot produce fully today — some equipment was impacted — so we are targeting the end of the third quarter. September is possible, but events are largely out of our control. Other projects are progressing: all projects have been launched, contracts awarded, and we have personnel on the ground for the seawater project, the associated gas project, and Ratawi Phase 2. We also have encouraging news on well productivity compared with the first phase. Execution is being affected because moving large equipment is difficult; smaller equipment has been transported by road but the larger pieces remain challenging. We remain dedicated to the projects, but there is some impact. It’s difficult to be precise, though a three-month postponement is a reasonable estimate; we will need to reassess once the situation in the Gulf stabilizes.
The next question is from Jason Gabelman, TD Cowen.
I wanted to ask the first one on the potential for windfall taxes. And 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 most governments implemented measures between 2010 and 2015 that remain in many of our countries. We had one limited impact in Brazil, where an export tax was imposed for four months; there are rumors of an extension, although it has been declared unconstitutional and is the subject of a legal dispute. The U.K. scheme has recently been increased so they cannot take more, and Norway is fine. In most of our production sharing contracts there are mechanisms you can see when looking at TotalEnergies' average tax rate: in an environment around $50 to $60 we are roughly at 40 percent, and in an environment around $80 to $90 we are closer to 45 to 50 percent. These mechanisms mean that when prices rise, governments take a bigger share. That is normal because our negotiations try to protect the low cycle by giving up a little more in the high cycle. We have not faced this type of conversation since the beginning of the crisis, so apart from Brazil I do not have any other situations in mind where this is under discussion, again because the mechanisms already exist in many of our production sharing contracts.
Great. And 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. And I'm trying to understand kind of what the cash flow split is between those 2 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're absolutely right. There are two different activities. One is the Russian activity, the Yamal liquefaction plant, where we are a 20% shareholder. Some cash flows have been distributed, but it's not straightforward because we respect sanctions. The question is whether the cash was distributed in Russia and when it can flow to Europe, because European sanctions have limited the capacity to transfer funds from Russia to Europe. Some cash has come back to TotalEnergies, but not all of it. We do not consider that part in our planning; we are cautious. It does not come on a regular basis. From time to time there are openings, but it is not regular. Some cash remains in Russia and we expect it is waiting for us. The other part is the European lifting, which is outside Russia. That business is handled by our U.K. and Swiss entities, or the U.K. entity, which deals with Russian contracts and receives the cash. For that one we have direct access to the cash. The magnitude of this business is around an average of $400 million, but it fluctuates because the contracts are linked to Brent. Depending on assumptions about Brent, you might see roughly $300 million to $400 million a year. It is part of the portfolio, but not a major situation for TotalEnergies.
The next question is from Henri Patricot, UBS. Mr. Patricot, we cannot hear you. Maybe the line is on mute. The next question is from Jason Gabelman, TD Cowen.
Just one question. Coming back to capital allocation. Last quarter, you mentioned that we're evaluating options to accelerate short-cycle investments in upstream. Where are you on these options? I mean it sounds like earlier that you might see CapEx unchanged. So are they just not being considered anymore?
No, no. Different subsidiaries have worked on it. There have been some proposals. We have approved a few, I think $200 million to $300 million this year. So the guidance of $15 billion may end up at $15.2 billion, but I consider that part of the global guidance; it’s not a real impact. And yes, for next year there is a little more because these types of actions are not only immediate. I would say probably $500 million of capital allocation acceleration could come next year. But again, it does not and will not change the global guidance we gave you last year, which was around $15 billion to $17 billion per year of CapEx; then we said $14 billion to $16 billion, and it will stay around the $15 billion to $16 billion range. So yes, we have taken some actions and that will impact 2027 a little more than 2026.
The next question is from Bertrand Hodee, Kepler Cheuvreux.
I 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 Q-on-Q, while at the same time, contribution from equity affiliates, 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 trading performance?
You are very good, Bertrand. We can add nothing to you. We are very transparent. In fact, we mentioned to you that there was an overperformance last quarter of around $500 million, and your $800 million. So you have an underperformance reversed not only from $500 million to less than $300 million compared to a normal situation. So you merit a certain distinction.
And the second question, probably on your comment that those long positions that did not work out in Q2 are now in positive territory. Is that a hint that we could be headed for an overperformance in LNG trading in Q3 by the same magnitude?
Exactly. But maybe we are only in July, so maybe it could be larger. I don't know. Okay, to be clear: yes, it could be of the same magnitude. Because the markets, when they are volatile, are volatile. When prices move $5 per MMBtu over 20 or 30 days, even 20 days, I can tell you these types of positions generate gains. But the results are not final on July 22; they are final on September 30. So we'll come back, but it's possible, yes, we might come back to you with the good news of the same magnitude.
The next question is from Fergus Neve, Rothschild & Co Redburn.
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. And then 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?
In July it looks very good. The average margin over the last 30 days was $31 per barrel for July. So it looked very good, and I think July is probably around $35 per barrel. It reached a historic record for me, more than $40, even $44; I saw one day at that level. Today it's a little backtracking because crude oil is going up. I have one observation since the Strait of Hormuz was again blocked on July 9. When you add crude oil and refining margin, we are almost at $130 day after day. I don't know if there is a trick, but probably. That's what I mentioned in my opening comments. On Papua LNG, we are working very closely with ExxonMobil, Santos and the government. The government has just launched the final part of the procedures, the local hearings. The objective is clearly to sanction all that before year-end; November is the target. We are aligning the interests of all the partners in the interest of the project, and we are studying how we can maximize synergies today between Papua and PNG LNG to deliver the most efficient project to the government, in close cooperation with the government. I'm happy to see that the different stakeholders share the same objective. We need to put together a few things; it's not easy, but I'm optimistic we can reach this sanction, and we are all working for that and are very aligned. On the Mozambique LNG project, it restarted in January. Today we are increasing mobilization of people on the ground; I think we are at 7,000 or 8,000 people. The project is progressing. We faced some difficulties because some of the equipment was being built in Dubai and various yards in the Middle East, so we had tough times getting all the equipment out. I think that's done now. The progress continues and today we are almost 45% complete. We still have a lot to build in Afungi and offshore. It's on its way with a target of 2029 for the first train, and we are working on it.
The next question is from Jean-Luc Romain, CIC CIB.
It relates to refining and the plan to introduce more green hydrogen into your system. Where are you with this? And are European regulations moving too slowly for you to make progress on that?
Yes, the French one. No, but we are working on it. Where are we? In fact, we have made progress; no, we have nice offers. As you know, the good news of the quarter is that the German parliament has adopted its own regulation. So today we are very clear on the German side, and Leuna will be able to maximize the use of green hydrogen. That’s good news. There was bad news regarding the Netherlands: the regulation has been adopted but not at the maximum level. I think the Zeeland refinery will be able to take roughly 30% of what we had planned to offtake. Without fiscal support, we cannot do that. We are working today with the last two governments: Belgium, where the drafts are not so positive, and France, where the drafts are positive but the problem is that fiscal reforms must go through parliament, which is not an easy task for the government. We’d like to have a definitive scheme rather than an interim one, because if we commit to long-term contracts of 10 to 15 years we need a scheme that gives us a certain level of comfort. It’s a very technical matter and one of the most complex topics I know: explaining RED III and what it means to produce green hydrogen in Europe to political leaders and securing support is tough. But momentum is building and we are working on it. We are not alone in this; in France we are working hand in hand with Air Liquide, which is also interested in these regulations. Progress is being made, but to commit to long-term contracts we need all these regulations enacted. That’s the beauty of Europe: you think a directive in Brussels is enough, and then it can take four years to implement in each country. I’m also concerned because there is a new directive, RED IV, under consultation that could revisit the definition of green hydrogen. Reading that is worrying because further regulation could make things difficult.
And the last question is from Ben Salem, ODDO BHF.
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.
Yes. Thank you, Ahmed. We continue to consider the Middle East an investable region; there's no doubt about that. Ultimately it's a question of risk and reward. Maybe the reward will be a little higher. But when I saw my U.S. competitors rushing to Iraq last weekend and the number of MoUs signed to develop hundreds of thousands of barrels, I wondered why U.S. companies suddenly want to see lower geopolitical risk while we, who have more, I would say, DNA in the region, consider it higher. So it's a question of risk and reward. It also comes back to my comments about having alternative routes to export oil to market. That said, TotalEnergies' policy and strategy have been to diversify the portfolio, which reinforces my strong belief that diversification is essential in this business. We've done it well in Brazil, in Africa, and in new countries in Africa. Of course the U.S. is attractive to us as well, and we are building a sizable position in the U.S. through capital allocation in LNG and integrated power. So we are fine. I understand the question, but when you produce oil and gas you go where you find it. If we discover oil and gas in Suriname or Namibia, we are happy. It's true we don't find oil and gas in Europe, and by the way we don't have the right to look for it. For me, the answer is to maintain our strategy of diversification, and that's what we will present in September. I think events over the last four months have demonstrated that this is the right approach: we have been able to supply feedstock to customers and not have to claim any force majeure for LNG customers, unlike some competitors, because we have diversified sources of LNG supply, including building a position in Mozambique. Look at the countries we have developed in the last three years — Suriname, Malaysia, Namibia. We are continuing to diversify our stakes because that's the reality of our business. This is not new in 2026; it has been the case for years. That's my answer.
Gentlemen, that was the last question. I turn the conference back to you for any closing remarks.
Yes. 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. So 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. So thank you for your attendance and happy holidays to all of you.