TotalEnergies SE (TTE) 2026 Q3 法說會逐字稿

Hello, everybody. Good afternoon or good morning, wherever you are. It's the third quarter results, not the first one, just to begin. So it's a live intervention, live speech. As Jean-Pierre will show you in a moment, TotalEnergies has demonstrated once again, in this quarter, its capacity to achieve an outstanding operational performance and to deliver a very strong set of results and cash flow, clearly reflecting the ability of the company to fully capture high prices.

I would say all is green, not only the different market indicators, but also the operational performance. And I must praise all our teams around the world that delivered these results. And I could add that all is green as well, not only for the third quarter, but also for the first month of this fourth quarter and probably for the rest of the year. Market conditions have been indeed very supportive for all commodities that we are selling. The oil prices started the quarter at $80 per barrel on the hopes of a lasting ceasefire signed between the US and Iran.

The MoU signed between the US and Iran finally holds again at levels above $100, $110 per barrel and the dated brent being today at $121 per barrel as a result of the broadening of the conflict to Bab el-Mandeb Strait of Saudi Arabia and reflecting the persistent volatility of the situation in the region. The petroleum product prices, diesel, gasoline have increased in a larger and unprecedented way as a consequence of massive disruption to the refined product logistics chain triggered not only by the conflict in the Middle East, but also by the unavailability of some Russian refining capacities due to the efficiency of the Ukrainian attacks. And so refining margins have reached historical records in Europe and in the rest of the world.

Gas and energy prices in Europe and Asia started to rally this quarter as countries have started replenishing their inventories in view of winter consumption. This rally consequentially pushed electricity prices up in some European countries where gas reflects the marginal cost of production of electricity. But beyond these favorable market conditions, the strong set of results highlights the strategic strength of TotalEnergies, the integration and the geographical diversification of the company.

I explained during our last CMD in New York that these two differentiating factors together with our leading position being a low-cost producer, make TotalEnergies best positioned to capture value from market disruptions. First, this quarter, we were able to fully leverage our integrated business model to capture margins.

In the oil value chain, integration has never been so relevant. We have been able to capture all prices from our growing upstream activities. We are taking full advantage of our midstream and trading capabilities to bring crude oil into our refineries and captured record high refining margins. This reflects highly valuable integration. The downstream have delivered the best quarter ever for an exceptional combination of record high margin and strong throughput increase as all our refineries are running up at full speed.

And SATORP is now back at nominal capacity since the end of the third quarter. And we anticipate, of course, same level of refining treatment in the fourth quarter. In the gas and LNG value chain, our LNG and gas traders were able this quarter to capture benefits of their long position on gas, which is now proving to be a winning position as gas prices have been rising during third quarter. With Europe attracting more LNG volumes right now and the TTF currently at around or above $30 per million BTU. LNG is still going up.

And we anticipate strong results as well for gas trading in Q4 and not only for gas trading for LNG trading more globally. Second, our geographic diversification allowed us to mitigate the impacts of the Middle East crisis on our production. The impact of the crisis in the Middle East on TotalEnergies' overall production was reduced to around 5% over the quarter on average, which was in the low range of the guidance provided last quarter.

Still, the company was able to grow oil and gas production by more than 3% quarter-to-quarter, supported by the ramp-up of projects launched in 2025 located mainly outside the Middle East. Excluding Middle East impact, the production growth even exceeds 4% year-on-year, clearly reflecting our diversification in upstream growth.

By the way, importantly as well, as we explained during the last CMD, during this quarter, we took a certain number of final investment decision, Cronos in Cyprus, Ima in Nigeria, Umm Shaif Gas Cap in Abu Dhabi and Absheron Phase 2 in Azerbaijan. And now all the projects contributing to achieving the upstream production growth target of more than 3% per year by 2030 are in execution phase. In integrated LNG, this geographic diversification, we are producing LNG in 11 countries and as well the length of our LNG portfolio allowed us this quarter to compensate the effects of Qatar volumes lost and not declared any force majeure to our LNG customers, which today is making TotalEnergies very popular in Asia.

Gas Asian buyers were lining up at our booth to negotiate long-term contracts. By the way, this result was also possible because we had a large LNG fleet tanker available at a cheap cost, which means that this, I would say, no force majeure had no impact, in fact, on our costs, on our global cost.

And we delivered that very efficiently to our customers. We also achieved some key milestones this quarter, establishing our LNG marketing JV with Kumul Petroleum, the national oil company in PNG for 2.4 million tonnes per year. And the signature of an offtake LNG agreement of 1.5 million tonnes per year, strengthening the diversification of our LNG portfolio towards fast-growing Asian markets.

So I would say that this geographic diversification that some we are considering some time ago as a weakness because being deemed to expose globally is considered today as a strength by our customers and a strong hedge against geopolitical risks. Finally, and very importantly, our operational performance across all business areas has been excellent again this quarter.

I would say, once again, the refining our refineries at full capacity, optimizing utilization resulted in an increase of nearly 10% of our refining throughput this quarter, enabling the company to fully capture record high refining margins in Europe, but also in the US and in the rest of the world, in particular, Saudi Arabia. The company once again demonstrating its leadership to control costs with operating costs of $4.7 per barrel, anchored strongly below $5 per barrel. By the way, this is the result of the cash saving program we launched in '25 in view of a bearish year '26, but the program is still live today and delivering. The power business also saw an increase of more than 20% in net production this quarter, taking, of course, full benefits from the integration of the assets from our JV with EPH.

Integrated Power is again well on track and will be net cash positive in '27. Given the company's strong operational and financial results delivered by each business segment this quarter. Given the sustained high prices, the full year 2026 cash flow is now expected to be above $42 billion and maybe around even reaching $43 billion, supporting dividend growth while anchoring gearing below 10%, it's already 9%, but will be lower by the end of the year. In this context and in line with the objective and the commitment of returning 40% of cash flow to shareholders, the Board of Directors has taken following decisions. First, we confirm the third interim dividend at EUR0.90 per share, up 5.9%, 9% compared to '25.

Second, the Board authorized share buybacks of $2.5 billion in the fourth quarter and also $2.5 billion share buybacks in the first quarter. The Board finally asked me to tell you that it reiterates its commitment to return 40% of cash flow to shareholders. And that if necessary, it might adjust upward the final dividend to meet the 40% return.

I will now hand over to Jean-Pierre to go through the details of the third quarter financials.

Thank you, Patrick. So I will start by commenting on the price environment for the third quarter of '26 versus the second quarter. We captured high prices across most commodities. Brent and liquid price remained elevated and increased throughout the quarter with the pronounced impact of the Middle East conflict. Brent averaged $97 per barrel during the third quarter versus $104 per barrel in the second quarter, down $7 per barrel, while the average liquid price was $87 per barrel.

Liquid selling price continued to reflect an elevated freight cost and decreased by $4.5 per barrel compared to the second quarter. TTF averaged $21.5 per million BTU, up 38% think last quarter average price of $15.6 per million BTU driven by low inventories and the upcoming winter season demand. Our average LNG price increased by 20% to $12.3 per million BTU, reflecting the lag effect embedded in our contract pricing formulas and the increase in spot gas prices.

But also the European refining margin, which includes cost of natural gas, CO2 and freight costs increased to an historically high level of $33 per barrel on average over the quarter 2.5 times higher than the last quarter, supported by an unprecedented combination of unavailability of Russian refining capacity, the disruption of the supply from the Middle East and global inventories at historical lows. In this high price environment, TotalEnergies leveraged its integrated business model and geographical diversification to deliver very strong financial results underpinned by the outcoming operational performance of all businesses and the company's ability to capture value upside in disruptions.

We reported indeed adjusted net income of $9.1 billion in the third quarter, increasing by more than 50% compared to the second quarter and cash flow of $12.3 billion. TotalEnergies delivered a strong profitability this quarter with return on equity at 19.6% and ROACE at 17.4%. Let me now highlight four key takeaways from the quarter. Upstream delivered production growth up more than 3% quarter-to-quarter, notably due to the lower impact from the Middle East conflict. Downstream achieved record high quarterly results with cash flow increasing by almost $2 billion compared with the previous quarter, underpinned by all our well-functioning refineries.

This allowed the company to fully capture historical high refining margins in Europe and worldwide. Oil trading activities also outperformed at a level comparable with the two previous quarters. Integrated LNG delivered very strong results, more than doubling compared to the previous quarter, reflecting the 20% increase in average LNG price. And the outperformance of LNG and gas trading activities in the bull markets. Integrated power cash flow generation continued to increase this quarter, supported by full quarter contribution from TTEP, our joint venture with EPH.

Let's now dive into each of the business segments, starting with Hydrocarbons. Third quarter hydrocarbons production was 2.47 million barrels of oil equivalent per day. On a year-on-year basis, excluding the impact of the Middle East conflict production would be up by more than 4%, supported by the start-ups and ramp-ups of the project launched since the beginning of '25 and benefiting from gradual return to normal oil operation in the Middle East.

Over the quarter, the impact on production from the conflict in the Middle East is limited to around 5%, which is in the lower range of the guidance given last quarter, guidance being 5% to 10%. Looking forward, we expect to maintain strong momentum with hydrocarbon production in the fourth quarter, excluding the Middle East impact, expected to grow by more than 3% year-on-year, in line with the annual guidance.

At present, we observed the impact of Middle East below 5%, mostly coming from limited export from LNG volumes through the Strait of Hormuz, but we note that the situation remains volatile. Turning now to quarterly results for E&P. The segment generated an adjusted net operating income of $3.2 billion in this quarter and a cash flow of $5.4 billion, reflecting production growth and sensitivity to declining oil price and rising gas prices quarter-to-quarter.

On the cost side, as mentioned by Patrick, we continue to lead low-cost operation with an average OpEx per barrel of $4.7 below our guidance of less than $5 per barrel of oil equivalent. On integrated LNG, the LNG production decreased by 7% quarter-to-quarter mainly due to planned maintenance, notably on Angola LNG and Ichthys LNG.

Adjusted net operating income was $1.9 billion and CFFO was $1.7 billion, underpinned by a 20% increase of average LNG prices and in contrast with the second quarter, positively impacted by the outperformance of LNG and gas trading activities in the bull markets given the ongoing conflict in the Strait of Hormuz and seasonality of the months. 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 above $14 per million BTU for the third quarter '26. Turning now to Integrated Power.

Over the first nine months of '26, net power reduction increased to 44.6 terawatt hour, up 25% year-on-year driven by the growth of integrated power generation portfolio, notably the commissioning of new renewable capacities and the contribution of TTEP's assets in line with expectation. TotalEnergies therefore on track to reach its annual objective in Integrated Power business to generate more than 60 terawatt hour over the year.

And cash flow from operations was up 7% quarter-to-quarter, at nearly $0.8 billion supported by the contribution from TTEP assets over the full quarter. Moving to Downstream. During the third quarter, Refining & Chemicals achieved record results driven by refinery throughput up nearly 10% over the quarter, underpinned by all refineries well-functioning in Europe and in the United States for Arthur. And the progressive return of the SATORP refinery in Saudi Arabia to its normal capacity successfully reached at the end of the quarter. Refining & Chemicals adjusted net operating income was up to $3.6 billion and cash flow was up to $3.9 billion, demonstrating the segment's ability to capture historically high refining margins in Europe and worldwide.

Meanwhile, all trading activities continue to outperform. Marketing & Services delivered solid results with adjusted net operating income of nearly $0.5 billion and cash flow of nearly $0.7 billion in the third quarter, reflecting higher unit margins that more than offset lower volumes. Let me reemphasize the strong CFFO generated by the company over the quarter of $12.3 billion, up 25% compared to last quarter. Net investments remained disciplined at $3.3 billion in the third quarter, in line with the annual guidance of the full year of '26 net investments of $15 billion. The company delivered an attractive shareholder return this quarter, totaling $3.7 billion, including dividends of $2.2 billion and share buyback of $1.5 billion.

At the same time, the company reduced its net debt underpinned by a free cash flow after payment of dividends of more than $6 billion and a positive working cap contribution of $3.1 billion during the third quarter. This reduction of the working cap notably driven by the increase in tax liability related to higher prices and an increase in suppliers payable related to the increased shipping costs.

As a result, the gearing improved by 4-percentage-points to reach 9.1%, already below the 10% level we guide at CMD for end '26. To conclude, the integrated model and geographical diversification of TotalEnergies continues to demonstrate the company's exceptional ability to produce and deliver reliable energy and to capture higher prices and higher margin with a growing cash flow that supports growing the dividend, deleveraging the company, investing to deliver accretive growth by 2030 and beyond and increasing share buybacks for our shareholders to $2.5 billion per quarter in the first quarter and in the first quarter '27. With that, Patrick and I are available for your questions.

Operator, please open the line for questions.

(Operator Instructions)

Lydia Rainforth, Barclays.

I really appreciate the quarter. Two questions, if I could. Firstly, just coming back to Patrick, what you said on the potential for the final dividend to be adjusted upwards. Are you thinking special dividend on that one? And then secondly, I know it's only a month since we have the Capital Markets Day.

But I did want to come back to the upstream growth ambitions to 2035 because there has been a lot of discussions about the resources that need to be added. And I know the ability to add resources at a competitive cost has always been a strength of TotalEnergies. And you've given us a lot of visibility on the plan for 2035. But the gap that you have, is that an unusual gap this far out? Or are you better positioned than you would expect or slightly weaker? I just want to get a sense of the urgency in which you might want to add resources or whether it's something that you're relaxed about?

Okay. The second question is just related to the third quarter results versus CMD. So just to clarify, we have no urgency at all to be clear. I think what we told you at the CMD is that we have already in 2026. Until 2035, we see a plateau of 3 million barrels of oil per day. It's quite unusual for an oil and gas company to have zero decline during five years. So and we gave you the list of the projects which are already there. So from this strong basis, announcing potential growth of 2% to 3% is not, I would say, there is nothing spectacular. 2% will be easier than 3%. It's just a normal, I would say.

And we have demonstrating or advancing our ability in the last 10 years, either through exploration or through access to DROs to, I would say, deliver this growth. So it's just a continuity. So we have no urgency. And secondly, I would say, just wait maybe with Monday morning, you will have the beginning of the answer to that. We'll make some announcements about access to DROs. You will see that we continue to be active on this matter. It's a permanent, I would say. I think the strength for TotalEnergies. Since 2015, we have consistently looked to, I would say, book reserves either 1P, 2P. And I think it's a strength of the company.

So that's just a question of trust. So we are very good, yes. And I would say, are you better positioned than usually? The answer is yes, because we have already a visibility of zero decline until 2035 from 2030 to 2035. So thank you, Lydia for the question. I hope I clarified. Maybe my English is not good enough. The question I just mentioned to you. Look, we committed to 40%, okay? If you take $42 billion, 40% with $8 billion of buyback plus $8.6 billion of dividend, it's okay.

If we are not at $42 billion, but we are at $43 billion. And I mentioned that figure during my speech, then, there is a lag somewhere of, let's say, $400 million, I would say, $500 million. So the question for the Board is just what I told you. The Board asked me to tell you that in that case, when we will decide the final dividend in February, in fact, we have a normal final dividend. But we'll consider, I would say, an uplift of the final dividend and the $400 million or $500 million represent $400 million is $0.20 per share, in fact.

We have 2.5 billion shares. We might consider in order to meet the commitment to put, I would say. I don't know if you call it special, an uplift dividend on the final dividend, not making. And we'll pay it together with the final dividend. But the way that we want to respect the commitment honestly. We will all be happy if we reach $43 billion rather than $42 billion. But that's, I would say, what I'm adding today. So first, some of you told us we are conservative on the $40 billion at the CMD, I am not sure. Honestly, we learn month-after-month. But today, maybe we are less. We said $42 billion and maybe even $43 billion and then we are committed to 40%. That's what you need to understand.

Biraj Borkhataria, RBC.

Just two, please. First one is on Integrated Gas. You had a really strong result. And obviously, you flagged the long gas position with the CMD and the commentary around that. I was wondering how we should think about the flow-through into the fourth quarter and sort of the exceptional element and the reversal in the third quarter?

And how we should think about the earnings sustaining at this level into the fourth quarter? And then second question is just on Uganda. Can we get a quick update ahead of the start-up and sort of commissioning activities and where we are now and risk factors and so on?

So on LNG, I told you during my speech. I think I gave you a good indication of what could be -- what we anticipate on the fourth quarter. In fact, our position, you've seen that TTF continues to go up, $33 per million BTU. And so we anticipate, I would say, I was looking to exactly what I just told you a few minutes ago. I just told you that with Europe attracting more LNG volumes right now and TTF currently around or above $30 per million BTU.

LNG is still going up. And we anticipate strong results as well as for gas trading in Q4, which means you should expect the performance in the same range for Q4. That's part of why when I'm trying to anticipate, I would say, the global cash flow for the year, there is today a range of $42 billion to $43 billion. I will add as well that we put in the forecast. We announced that the LNG price will be above $14 per million BTU.

In fact, it was based on an assumption on TTF, I think, around $25 or $27. At $33, we are more next to $15 than $14, I would say. So there are -- I see only potentially, I would say, some good upside on the LNG business in the fourth quarter. That's what I could comment on this one. On Uganda, I think there are two different things.

We have, of course, the EACOP, the pipeline, which is progressing well because the intent is to start up Kingfisher, the offshore production this year. And so that is, of course, to start up Kingfisher, we need the EACOP to be fully commissioned. So we are at 95%, I think, or something like that. And as I said during the CMD on that, we expect the start-up during the first half, I think, of 2027 because as I explained, we had some delays on some equipment going through the Strait of Hormuz. So we have, let's say, a six-month delay. But all the teams are today working hard in order to deliver this production by first half. That's what I can tell you on your two topics.

Jason Gabelman, TD Cowen.

Patrick, you commented at the CMD a month ago about potential appetite for US shale acquisitions. And we've had investors asking about those comments since then. Prior to the event, you previously said you were interested in shale gas rather than shale oil. So I was hoping you could clarify if you want to grow your oil business in the United States and if it involves shale.

And I'll ask my second question now as well. The other focus from investors that we've heard is on the uncertainty in France. I was hoping you could talk through Total's earnings exposure directly to France, potential risks of new taxes the government can impose on Total? And then any thoughts around impact on cost of capital given what's going on in the country?

Okay. Thank you for the two questions, which will help me to clarify the first one. Let me be clear, our M&A is countercyclical. I'm not sure that acquiring any oil production in the world today would be a lot -- will be countercyclical when you see the price of oil. So no.

Secondly, we always said in the US that our priority is on gas, natural gas. We have a big LNG position. We want to integrate the value chain. By the way, today, natural gas is quite low and it's more countercyclical today, it's $3, I would say. But there are also some liquids with gas. That's all my comments. So I like gas. I like the liquids as well. There is no position of the liquids.

Then -- so that's the better priority today. We said that we were targeting something like 1 BCFE. We want to continue to grow in the LNG in the US. So 1, 1.5, 2 BCFE would be for us a good target. So keep that in mind. My comment has been extrapolated. I just continue to think that liquids is good as well as gas. That's all. And the US is a good area of investments for TotalEnergies.

We are, I would say, compared to our peers, not weaker, I would say, less exposed to the US depends on that exposure. We have a large base of US investors. So Board is pushing supportive of move in the US if we have the opportunity. But again, as I said also today, it's more -- we have a strong base of growth today. So it's not to grow. It's more to the in order to the position to be hedged. So it's a question of finding reasonable access to resource.

We have done already three JVs natural gas. We continue to work as well on this mode of continuing to develop the gas position. We'll have some news in a few months on that. France, good question. So first, I repeat to all of you. The French state is not a shareholder of TotalEnergies. I spent my road shows to reexplaining that to all our investors. So maybe you could help me all of us, all of you by explaining that. There is no direct interest of French state in TotalEnergies. There is no golden share, there is no say.

We are a publicly listed company, which is managed independently, first comment. Second comment, we are a global company, largely international company. I think our results or our cash flow, let's say, and the capital employed is around 7% is located in France. I mean to give you a round figure. I don't know if it's 6%, 7%, 8%, depends on the year.

So it's not a French company. It's headquartered in France and we are proud of that, like all the French people. We have grown on that basis. I think it's even sometimes a strong advantage in some parts of the world. Geopolitically, we are the only non-Anglo-Saxon major oil and gas company.

So it has some value as well. So I would say that's the second point. Third, on taxation. If you learned, if you had listened yesterday to the debate of the parliament was a lot about the taxation of TotalEnergies. The government has pushed back all the amendments. None of them has been adopted. And because why? Because again, I repeat. We took this initiative in the country to put a ceiling on the gasoline and diesel price for the customers. We have been very clear with all the authorities that if they were taxing us, then we will, of course, give up this ceiling.

And I think today, government rightly, I think I saw consider that what we is going as a protection to the customers is largely worth, I would say, politically, what would be a taxation. By the way, you probably noticed and France did not sign the letter to the EU Commission to ask for a special taxation of oil and gas companies. So of course, politics is politics, but that's the situation. And I'm convinced that our direct action to customers in France was the right move that we've done. Of course, I know it's the Board, it's innovative, but it's a way to preserve.

And by the way, we have the benefit of it in terms of image with our customers. I'm sure you have asked questions. The cost of this protection is, of course, more expensive today because with the diesel and gasoline going up, it costs us is around, I would say, by end of October, around $500 million as we anticipate, but I remind you that in 2022, we paid more taxes. By the way, for French people and French auditors, good news is that because we have good French business this year, refining in France are running well. We should pay around EUR500 million of corporate tax.

So if I'm adding both, it's an exceptional contribution to the country of EUR1 billion, I would say, which I think is quite sizable with a direct impact to customers. So that's my comments. Again, we don't control politics. But we do our best in order to explain that today. And I think it's more and more perceived by TotalEnergies is an asset for the country and should be as well considered by that by the different leaderships.

Martijn Rats, Morgan Stanley.

Two questions from my side as well. I just wanted to come back to the CFFO figure of $42 billion to $43 billion. Because if you look at where commodity prices are, dated Brent is $120, TTF nearly $100 yesterday, refining margins pretty darn good. If the comment is also that trading in the fourth quarter will be once again strong, it wouldn't be beyond the wit of man that the fourth quarter would be even higher than that. So which then raises the question whether this $42 billion to $43 billion sort of indication either just embeds some conservatism because, okay.

These prices are on the screen now, but they might change. Or whether there might perhaps be some working capital outflow or some payments that might be overlooking that might be sort of a bit unusual in the fourth quarter. I presume it's the former rather than the latter. But I wanted to raise the question nonetheless whether there might be anything in the fourth quarter that we should be aware of from a cash perspective. And the second question I wanted to ask relates to the hybrid.

There is about EUR1.7 billion in the net debt from the EUR1.5 billion hybrid that you called. And I was wondering what your approach to hybrids now is. Would you expect the hybrid to be refinanced with another hybrid? Or is this hybrid now called sort of the end of it? Can you perhaps give some clarity on that? And also how that is impacting the various line items in the balance sheet? Maybe some detail on that because that can be quite tricky to figure out.

First, no, I think I said cash flow from operation will be above $42 billion, it might be around $43 billion. So with that, honestly, Martijn, I don't know if you know and whoever knows in the planet, what the US. President will decide after the midterms in the Middle East. I don't know, nobody knows, in fact. So there was an article in the Wall Street Journal, but it could be a short but with all conflict.

I don't know, we see. So what will be the impact on the market? Honestly, today, it's quite -- I mean, I'm somewhere amazed. In the spring, everybody and the forward curve was all the markets were behaving as if the war will end by summertime. I don't know where it was written.

The forward were lower. Today, everybody believes the market believes the war will stay for long. I don't know. So honestly, I have by giving you, I would say, a guidance of about $42 billion and around $43% billion, I think we are probably right in the ballpark. If it's more, again, the commitment of the Board, if it was $43.5 billion, for example, you will get back the 40% of the additional cash flow from -- and at least on the final dividend.

That's what I can tell you. There is no way. The second point, when we speak about cash flow from operations, there is no impact on working capital. We don't -- honestly, on the fourth quarter, that's true that this quarter, it's quite unusual. We had, I would say, an inflow -- quite a big inflow in the third quarter, generally the fourth quarter.

We explained you why. We anticipate, but it's very difficult to be honest, to anticipate working capital movement because with the price of oil, which has an impact on all the inventories, et cetera, where the company, where will the price of Brent will be end of the year, I don't know. Today, I would say we anticipate a plus 1, minus 1, I mean, a neutral position on the fourth quarter under the control of Jean-Pierre. And we don't have any unusual cash items that we anticipate for the fourth quarter. So again, I would be happy to have been wrong, but I think we give you a good guidance today.

And if we are wrong because we make more cash flow. That will not be bad for our investors because again, we return 40%. The hybrids, hybrids, it's a typical topic for Jean-Pierre, which is an expert in hybrids. So I will give the floor to explain. But today, in fact.

Yes. That we call hybrids maturing in October, in our balance sheet, will impact our balance sheet end of September EUR1.5 billion, so $1.7 billion. So year-after-year, we decreased the hybrid stocks. So we'll see in the future the strategy that we will follow on that topic.

No. But I think it's important Jean-Pierre, because of the cost of hybrid.

Yes, it's 3%.

It is 3%.

Yes. At present, yes.

It's a question for us at 3%. Today, if we issue a bond, it's about 3% to 3.5%.

4%, yes.

So why should we get rid of this hybrid at 3%? Of course, the question will be and it's a good question linked to what will be the perspective of the interest at which price could we refinance this hybrid or not. But again, and it's linked to, I would say, the low gearing position. If we continue to have some cash flow, of course, this could impact the way we manage the different source of, I would say, treasury for the company. This is one of them.

There are also, as you know, some standards. And standard is the right name discussions regularly with rating agencies. And at which point do we consider that hybrids are equity and at which point they become a debt. So that's part of the debate. Again, for me, on this topic, I would say to you, what is the most important for as a CEO is what is the cost of the debt.

And this is the cost for the company because this is without cash. For the hybrid, or just call the bond I don't see much difference from my office. So that's the policy that we are following on this topic. So to have the detail of the impact of the balance sheet, I think before to explain you that, Martijn, I will be, we will need the Jean-Pierre to explain that to me. It will take a little time.

So I recognize that.

Okay. Thank you.

Christopher Kuplent, Bank of America.

Patrick, I'm going to keep it to one question on your outlook regarding Europe's gas prices and the markets that we now enter into. Given we have heating season and you have, I guess, more insights than we have into what's happening at Yamal. Do you think with the re-routings going on in 2027 that Yamal can maintain its utilization? Or do you think there will be a net loss of LNG volumes because it will be harder to send tankers around the world if Europe is no longer taking it?

I think you have the answer in your question. Because as you know, first, on the outlook of European gas price, I would say it's quite clear that we are entering in a dangerous period. We have seen the price has reached as anticipated by the EUR100 per megawatt hour. So it becomes to be political, I would say, a strong signal. It's clear that, unfortunately, winter season is the peak season, but Qatar has restarted some LNG production and exports.

But today, in September-October, I would say you had more or less around from Qatar or from Abu Dhabi, by the way, because both countries are producing. We had only 25% of the normal LNG tankers flow going through the Strait of Hormuz compared to pre-war. So only 25%. That means that you have quite a big volume knowing a month is more or less 6 million tonnes, 7 million tonnes, 8 million tonnes, 7 million tonnes. If you have 25%, you have a lack of LNG and this will be useful.

So that's true. But there is a stress. And today, you have, I would say, a competition again between Europe and Asia to get this LNG, the remaining LNG flowing to Europe. And so Europeans are ready to pay for that, so that's, I would say. Yamal, as you know, from 1st of January '27, Yamal LNG will not come to Europe anymore to the EU by the sanction regime.

Yamal was representing, in fact, more or less 15 million tonnes, I think, to Europe in '26 or '25, 15 million tonnes, 1-5. The rest of the production of Yamal, which is around 19 million tonnes or 20 million tonnes, if I remember, is going to China to Asia fundamentally to China. So as you also know, there has been an amendment to the sanction in July in which there is Dynagas which is a EU chip owner of LNG tanker has been authorized to ship some LNG from Yamal outside of the EU. So that means that this fleet is limited. You don't have -- it's a limited LNG fleet.

And of course, there is an impact where will the LNG go. If it goes to Mediterranean Sea, there is not much difference with the EU. If it has to go to India, of course, it's a longer trip. If it goes to China, it's even longer trip. So on our side, historically, we had -- I don't want to make 5 million tonnes of LNG transferred with Yamal.

There is 1 million tonne, which is, in fact, not possible to -- because of the sanctions for different reason which is not eligible. So we have four. And when we make the math today, we think that we might offtake between 3 million tonnes, maybe 4 million tonnes, let's say, 3 million tonnes. It will depend again about where this LNG will go through. So I just described you for TotalEnergies, just to explain you.

But I don't have the full picture of the Yamal, to be honest, because we have limited today our interest only on the -- what can be done according to the EU sanctions. But yes, the answer to you is, yes. There will be an impact if you have no, less -- the EU was a natural destination from the LNG tanker just because of optimizing the shipping freight, in fact, the shipping costs.

So the fact that it does come to EU definitely from January 27, will have an impact on the capacity of the plant to export its full volumes. I don't have a clear vision as well, to be honest, about the relationship today between Yamal and the Chinese off-takers because this is also the other part of the equation.

So that's my comment on this one.

Michele Della Vigna, Goldman Sachs.

Congratulations on the strong quarter. Two things I wanted to ask. First, in a quarter of unprecedented freight rates, I was wondering if you could tell us a little bit how you think about your current tanker portfolio? How much is on long-term rates versus spot? And how this impacts your realizations and trading capabilities?

And then finally, we've seen a big increase in appetite for long-term LNG contracts trying to -- with customers trying to diversify away from Hormuz. I was wondering if that is leading to an improved in the pricing. I would think recently, the oil-linked contracts have been around 12.5% oil slope, if we are seeing any improvement on that?

So two questions. Thank you. First, freight rates, I think it's a new topic. I never had a question since I am CEO about freight rates, they become popular, but different comments on this one. First, you probably noticed that our liquid realization, there was a difference between the third quarter and the second quarter of $6 per barrel.

The $6 per barrel represents more or less the additional freight costs, which in fact in our portfolio quite limited because our policy. In fact, today, we have some long-term, medium and long term, I would say, charter, which represents more or less 40% of the equity that we offtake. Why 40% is a good figure? Because, in fact, as you know, our average taxation rate on upstream is around 45% or 40%. That means that we are somewhere trying to neutralize the impact on our equity crude oil of, I would say, variable freight.

The second comment is that all charter with medium and long term are really with fixed rates. We don't sign including TotalEnergies charters, which will be linked to, I would say, a spot market. We don't just reserve the capacity. We have a capacity. We have the tanker plus freight.

And of course, our traders during this quarter and I think next quarter are benefiting today from having this fleet available, which, of course, is giving some positive results to their value chain, in fact. So that's, I would say, the second strength of the positions. So it's impacting, I would say, positively trading capabilities. And then, of course, it's up for trading, by the way, for the rest of their business. They are also negotiating its job access to third-party, I would say, tankers.

One of the success of the third quarter, which I think will move on in the fourth quarter is that they have been able to go -- to have access to some tankers going within inside the Strait of Hormuz of taking in particular, some erratic crude oil and then exiting and then making this trade generating some positive results. So that's our philosophy on trading rates. And I think there is a difference between different companies because some competitors have some charters but linked to the spot market for freight, which is not our case. When we charter, we charter on fixed rates. Yes.

Second question. It's true. But again, as I mentioned during my speech, at Gastech, we had a number of long queue of customers coming to us. Clearly, there is a trend there in Asia, I would say, to try to escape from the volatility of the JKM. JKM is not very popular.

It was the case in '22, we tend to forget in '24-'25. Today, again, this volatility clearly for these economies is not good. So they are coming back to ask linked to Brent. And of course, in such an environment, there is a trend for some of them to move from 12% to 12.5%. It's not -- the improvement is not as well, I would say.

You don't pitch today higher than 12.5%, I would say. But again, it's negotiation. So it depends where you are, of course, where the LNG is procured. We just -- in short, we are just commercializing the Papua LNG, I would say, volumes, 2.4 million tonnes with Kumul. And we have some good results from this perspective, which help the profitability of Papua LNG.

Alastair Syme, Citi.

Patrick, just one question. I wanted to get your thoughts about the current environment in downstream and whether that makes you think any differently about investing in that business. I'm really thinking about geographical mix or pushing more into biofuels or mix of assets versus trading. Is there anything on your mind from what we've seen in recent months?

I've been blunt during the CMD. I told you no, I will not invest in new refineries and maintain that position. I think it's quite exceptional. Of course, it encouraged us to maybe consider maintaining these capacities and that's all I thought. Biofuels, honestly, it's a complex economy.

It's a regulated economy. So there might be some pockets. But we have to be careful about the way that these regulations will evolve. There is in some countries a trend to more biofuel. But in Europe, there is always a debate between food and biofuel, which is continuously impacting the development of that business.

So I'm a little -- we have been opportunistic. We will start up as a concrete biorefinery in this quarter. So we'll have access to more HVO. HVO seems to become a more popular fuel in Europe. There has been a deal between France and Germany about the new light vehicle regulation where the French have accepted vehicle, ICE vehicle, which could be supplied by 100% HVO would be acceptable.

So we don't know for which volume because it's a matter of volume. But there is something happening there. We are -- all that is regulated. We need, of course, to be sure that this regulation will change again in a few years. In our environment today, I would say, by the way, so we are -- now what we've done fundamentally was to maintain, reduce the European exposure because of the trend.

This is a question mark we maintain outside? We have developed our platforms in Port Arthur and we have developed it by integration of petrochemicals. We have this big refinery of Amiral which we have of SATORP, which will complement by Amiral. I think it was the right strategy to go where the energy is cheap. In fact, for me, you make refineries, it's better to go where energy is cheap. That's very simple. So that's I would say. But I will not -- we will not change our strategy. Our strategy is fundamentally oil and gas upstream. It's integration and maintaining, I would say, downstream as a cash flow.

And I think today, it's a super cash flow. So that's good for us. And continuing to invest in integrated power, which has a good momentum, by the way, today in both sides of the Atlantic. US and Europe with all this AI and activity.

So I would say I don't see an inflection on the business. Having said that, the question will be, again, to consider that the midstream assets have a value, an opportunistic value and then taking decisions to shut down might be more tricky than it was before. So that's, I would say, the strategic conclusion, but we will review. And maybe my question would be different if I see three years in a row of $20 per barrel of refining margin. But for the time being, I'm happy with what happened.

I think the refining margin in Europe will remain quite good, quite strong during the first half of '27 because we will embark the consequence of the crisis, low inventories. Beyond, it's very difficult to say what will happen. And honestly, that's one of the most complex questions for us is what assumption do we take on refining margin for 2027 for the budget. So don't ask me because we will depend on mood on February -- in January or December or January. We'll see.

Matt Lofting, JPMorgan.

I'll just ask one on capital allocation. Given the strength of position that this year's cash flow and deleveraging creates for TotalEnergies. Did you see any further opportunities outside of the comments that you just made on refining to accelerate the strategy through incremental organic investment, which can further enhance the business' cash flow leverage to price whilst also helping France and Europe solve for energy security? And if so, in what areas of the businesses could some of those opportunities sit?

Honestly, I think for us, first, no. We have a strategy. We have a plan. We will not be to be procyclical, but certainly, we have more cash at the beginning of the mistake or the short-term mistake. So fundamentally, yes, there is a point.

I would say, yes, on the point. But we -- as I said during I think the CMD, of course, today, making infill wells to produce more oil in Angola, in Nigeria, there are opportunities. We will review their budget soon. If they are asking $500 million or $300 million, I will not say no stupidly because it's a short-term delivery. So of course, this is what this is, for me, the short term, the short cycle.

CapEx as we can easily, I would say, arbitrate. I think that one of the lessons is that on the question is, of course, we are looking to -- do we need to have, for example, where I'm ready to consider to have more, I would say, working capital is maybe more LNG charter if we need to be long on the midstream assets? I would say, that's a possibility chartering not to be perfectly efficient, but to have some margins in order to be able to capture the volatility. That's one of the lessons. I would say investing in some pipeline in the Middle East because this is part of the security of supply.

It's also giving value to our own assets that I agree. To invest in Europe for energy security in fossil fuels, I will need to see a different Bible at the European Parliament, to be honest. I'm not sure we are still there. So I'm honestly, let's not jump suddenly in that direction. I just mentioned that we could maintain our business today, and that's to grow in fossil fuels in Europe.

I need to hear a different narrative from the European political leaders and I'm not sure they are still there. But again, we work with them on that. But our investments for TotalEnergies, honestly, when we contribute to security of supply of Europe is more when we invest outside of Europe, investing in US energy, investing in Brazil on oil, investing in Mozambique energy, that's contributed to the security of supply of this continent. I think it's more our DNA. We have been created 100 years ago on this, I think, assumption and I think this is what we do. That's my comment. So discipline on capital allocation is a key word.

Kim Fustier, HSBC.

I have two, please. You've just referred to potentially participating in pipeline routes through Abu Dhabi, Iraq and Syria. What would you need to see in terms of utilization, tariffs and contractual protection for these investments in US infrastructure to earn an adequate return, especially if this capacity might be valuable only during periods of disruption? And then secondly, given the very high cost of moving crude long distances, have you sort of changed your crude sourcing or refinery optimization to reduce freight exposure? And does your integrated trading system allow you to protect your realized refining margins better than, say, regional or local refiners can?

Well, first question, we are discussing. We are discussing today on different schemes. We are participating to two projects. So I cannot today, I would say, I mean, answer precisely. There are negotiations, so I cannot enter into commercial discussions today with you.

Again, I think at the end of the day, the right word is that we need to be sure that the upstream revenue is not moving to the midstream one. So it's a question of balancing the position between the upstream and the midstream. And I think that's the question. So question of protection, again, yes, I know all that, but this is being discussed. And when we'll have better clarity on it, I will come back to you today.

It's premature to comment on that. And I don't want to interfere today with any of the discussion. The second one, it's a permanent, I would say, optimization of the crude slate of refinery is part of the permanent job of what we call refining the refiner optimizer, working very closely with the traders. We have, in fact, an organization in Geneva around the same date. But we have the refining optimizer just next to the crude trader.

And they permanently look to the different slates. And when we lost the Russian oil, we had to find other slate for refineries. And today, of course, it's an optimization, which integrates, obviously, the cost of shipping. That's part of it. When you raise before it was, I would say, cost of shipping was 5% of the cost of Brent, I would say, $2, $3 per barrel.

Today, we speak about $25 per barrel. So of course, this is part of the equation to optimize the supply of the refinery. Of course, if you can have access to some barrels from Norway, oil barrels from Norway, it's more efficient and from longer distance. But this is why I think fundamentally of our model is very efficient integration. At the end, in our results, as you noticed, refining chemicals.

This is the reason why we integrate in one segment, refinery and trading because this is -- for me, it's not us to decide what is the current price of price. What I want them together is not to have a fight between traders and refiners but to optimize the supplies of the refineries, which, of course, has a value for our traders. By the way, just to clarify for you. In our European refining margin, but I'm sure you know about it. It's not a pure difference of petroleum products minus crude oil.

It integrates in the European refining margin, the cost of the freight, the cost of natural gas and the cost of CO2. That's why when you see $50 in the U., where, of course, you have no natural gas is very cheap, energy is cheap. I would say there is no CO2 and the freight is limited to pipeline. Today, Port Arthur is benefiting more from $50 per barrel and not from $25 per barrel. So the indicator is taking into account this long distance impact, which could have.

But again, we optimized and we changed the full slate according to what is the best mix. Of course, we also optimized considering the slate of the products. If we want to make more diesel we select crude oil, which are being able to deliver more diesel or less fuel than gasoline. That's also part of the equation. It's very interesting job for young people to optimize permanently the refining optimizer.

Maybe, Kim, you should be invited by one of them during one day, you see what they do. We have more interest to do that.

Doug Leggate, Wolfe Research.

Patrick, I wonder if I could take two quick ones. First, your gearing is now under 10%. How much lower are you prepared to allow that to go? I assume deploying windfall cash flow to the balance sheet is still a good idea. And then my follow-up is, have you go back to a question from earlier regarding the post 2030 visibility, a really simple question. With what you know today from the portfolio, what's the most likely way to fill the gap to growth? Is it exploration, new project entries or M&A?

The second question is pretty easy. You look to our performance in the last 10 years. It's DROs, access to new projects is fairly the easiest one. In particular, if you are able to make some direct discussions where we have been quite good at. So that, I would say, when you look down, exploration is also part of it, I would say M&A, it's another topic, a different approach.

And it's not when we speak when I mentioned the 2% to 3%, we didn't have big M&A to be clear with you, just to clarify. The largest M&A we've done in E&P was Maersk Oil historically for EUR8 billion. So when I mentioned the 2% to 3%, don't interpret that as an announcement of a big M&A. If there was a big M&A will be on the top. So the base will be higher.

So that's not certainly in our mind, but fundamentally, I would say 70% DRO, 75% DRO, 25% exploration, like we have done during the last 10 years. First one, it's a good question. I had several times this question, so it's good to hear. I mean there is a point there, which is also -- it's quite complex equation because you could look at it from a financial point of view. There is a point today where I mean as long as the interest rates are low and that we deliver 4% or 5% of the debt and we have a reason of 5%, I don't know why we would go at 0%.

There is a point where we could see a financial balance. Then you could also say, which is in fact, also shared, that's why the Board is today declined will be a very strong balance sheet. We have a reward of prices. We don't know where we will go. Today, I would say it's a crisis which is pushing price up.

You could have another crisis like we had in 2020, price will go down. And so to have a very strong balance sheet will allow us to swallow this crisis. Our two US peers in 2015 were ended positively and it helps them a lot. I think the journey of the two companies was quite different from '15 to '25 to the journey of the European measures partly because that.

So that -- we are still -- I mean I will be happy to face really -- I think to face that question practically. Maybe for some, we'll have to continue to evaluate the point in and same to say where we go. But there is no, but to be pragmatic in the way to again manage global cash of the company, knowing that I noticed that some of you count the lease, et cetera. So we need to look at all the equation as well. So some of you have reported that we are not yet under 10.

We have 14. So to be under 10 for some of you, I need to be under 6, if I understand correctly, the comment this morning. So maybe my objective to be at the 6, so that I will stop these comments that we are not at 10 versus 14. So we'll -- I can work on that. Maybe it's easier as the first time.

Okay. Maybe just for clarification, Patrick. Do you see any value in a special dividend?

No, I told you I answered to that. I mean I've been clear. We tested -- there is a value if you announce it in advance. So in fact, what we are just doing today by telling you we can put a small -- a top-up on the final dividend, which would be 40% of the difference of cash flow to meet the 40%. I give you an equation today.

I told you today that 40% of the cash flow minus $8 billion of buyback that we have minus $8.6 billion of dividend will be the base of this, I would say, top-up of the final dividend. That's the way we will work on it. So -- but again, what I will notice when we were clear at the CMD when we made. And my investor team has done the road show with all the investors that a large majority, not all of them, of course. But I see 80% or 85% were more in favor of deleveraging than a special dividend.

So because the special dividend, we need to put a formula consider that today with 40% of cash flow, we have a sort of formula. But we could also match it directly with the buyback. So it's -- I don't want to -- the buyback is a normal way to match the 40% this year because we are, I would say, running because the positive or high results. We'll do it by putting a top-up on the final dividend.

Mark Wilson, Jefferies.

Just two points, Patrick. Maybe you could clarify on -- you spoke before about some LNG moving out of the Gulf. There has been reports of volumes getting back to pre-war levels in terms of oil in some reports. Could you give us your understanding of movement around the straits today or in the last few weeks? I appreciate it's volatile.

That's the first one. And then the second one is the Venus development we continue to wait for. Should we be expecting that in the very near future and the moving parts, any movement on that long license extension agreement?

In Namibia, we are starting the drilling of the Mopane well this month. That's a good news. Second news, don't listen to contractors, but listen to the operator. And I think I said everything during the last CMD that we are optimistic to reach the FID, okay? First point today, what we can say on Hormuz, in fact, globally, you could say that there were 20 million barrel of oil per day going from the region, the pre-war.

You have 5 million, 6 million through Yanbu, plus 2 million from Fujairah and you have 10 million, 12 million from Hormuz. So that 20 million are going to, crude oil, are going to the market with different routes. So we are around for most amounts, 12 million barrel of oil per day, which represents six tankers per night or less. It is 2 million barrel oil. The VLCC is 2 million.

To be honest, it's a new policy. The three NOCs have decided Aramco, ADNOC, Kuwait, but also Qatar for crude oil, have decided that they have their own tankers, old ones, they go through. If they are attacked from Iran, but they have decided that now they have to go through Strait of Hormuz. On LNG, it's a little more tricky because LNG tankers are a little more sensitive in case of, I would say, attack. Again, I mentioned, I said during my -- just -- I think the previous question.

That what we have observed today is that you have, let's say, 25% of the move in the last two months compared to pre-war. So around, I would say, 1.5 million tonnes to 2 million tonnes compared to 8 million tonnes. I don't know if it will go up or not. I think it's a decision which is more complex because it's more sensitive. LNG tanker is a little -- and the value is not exactly the same. So but I would say decisions which will be taken by the authorities and we are following that.

Henri Patricot, UBS.

Just one question from my side, sticking to the Middle East and the Ratawi project in Iraq. Can you give us update on what you expect in terms of the production ramp-up from the project in the current environment?

While we are moving up. I think we are targeting to move to -- we are already producing. We are already producing more than 100,000 barrels per day. I think we are starting right now, I think last week, this week. We have started the first gas project, the first what we call GMP25, I think it's 15 million per day or if I remember well.

And the full Phase 1, which is supposed to reach 120,000 barrels per day will be done by November. So we are really today ramping up on the oil side and on the gas. So the first phase of Ratawi, for me is done and then we are working. We have mobilized, I would say, on the -- we have 3,000, 4,000 people, I think I was in Iraq recently, 4,000 people in the field to build the full field, which will reach 110,000 barrels per day and 10 million scf per day of gas.

Bertrand Hodee, Kepler Cheuvreux.

Two quick ones. You had an under lifting position in your UAE offshore production in Q2. I was wondering whether those under lifting positions have increased in Q3? And what was the impact on E&P results and cash flow and whether you can signal whether this will improve in Q4 or not? And the second question is you mentioned that Qatar LNG export is probably back to 25% in October. But I was wondering whether your train in Qatar has restarted or not?

No, the second question is clearly no. The Qatar authorities are doing that. They are big -- they are commercializing most -- in fact, as you know, most of the LNG is commercialized by Qatar LNG, in fact, Qatar Energy, I would say themselves. So I would say the supply contracts we have are in force majeure and I think they are force majeure for long. Today, they prioritize, obviously, their own customers for what they can export, which is quite limited.

So no, we are continuing to ensure the supply of our own customers without the supply coming from the Gulf. But it's okay. I commented that before. Yes, then the lifting offshore UAE because it was difficult to go in the Gulf. We have done some liftings in the third quarter.

And -- but at the same time, the production is back almost to the normal level. So that means that, yes, we are in an under lifting position. To give the accounting impact on another lifting position, Bertrand, as I'm a little late because I know that Wael wants to speak at 3:30 PM after me. I will ask you just to go to the experts on the accounting. It's not me. It's Renaud and his team. And so Renaud is not an expert, but he has some people in his team which are good in accounting. Sorry for that. So yes, we have an under lifting position. We try to minimize it.

We do our best. But we are not the only one. I think all the IOCs are in this situation and we'll catch up as quick as we can, but all that is not an easy task. We are not national companies with our own tankers to expose. We have to pay insurance costs and all that.

Fergus Neve, Rothschild & Co Redburn.

Just a couple of quick ones on I-Power, if I might, please. It was good to see another strong cash flow ex-working capital performance from I-Power this quarter. I was just curious what cash generation and asset sale proceeds you envisage in 4Q to finish 2026 free cash flow balance? And how much of the 2027 positive cash flow target depends on further farm-downs? And then secondly, just on the return on capital employed improvements expected in I-Power. When do you think we should expect to start seeing those coming through given that it's been a little weaker over the last couple of quarters?

Okay. It's a good question because we have, in fact, in the fourth quarter, two. We have announced two important sales down, farm down to KKR, for almost 2 gigawatts between Europe and the US, representing an easy global of $3 billion. So it's quite big. That means that we'll get the impact.

And by the way, I don't have any questions, but I saw some comments on organic CapEx. In fact, again, our commitment I repeat the commitment is $15 billion of net CapEx, which will be reached because we'll have, I would say, some proceeds of this farm down during the third quarter. It's almost $1.5 billion. The impact on the CapEx is a little higher because we spent some money during the year, which will be recouped. And you have also an impact -- a positive impact on the cash flow from operation.

I think the target for it's around $800 million, I think, for Integrated Power. We have already almost $800 million this quarter. And we should go up because I think for the year, the anticipated cash flow from Integrated Power for the full year is around $3 billion, around $3 billion. We told you that it might be balanced this year. And free cash flow, we are more the CapEx -- net CapEx will be around $3 billion.

I think the cash flow, which are expected is $3 billion. So you will see an improvement, which is also coming, of course, from the full effect of the JV with EPH in the accounts. So I would say, yes. We are on the way to, again, '27 will be free cash flow positive. And integrated power will contribute to the dividend of the company.

Ahmed Ben Salem, ODDO BHF.

Just one question on the geographical mix. So you have materially expanded your US offshore acreage with Chevron over the last 18 months. Is this opportunistic or part of broader strategy to scale up in the US Gulf? And what is your long-term ambition for this basin?

Yes. Thank you for the question. It's a good question. In fact, you probably noticed that we have done some exploration, I would say, deal done with Chevron. In fact, as you know, yes, we have an ambition to continue to grow in the Gulf of Mexico.

Today, all our assets are operated by Chevron. At Tahiti, Jack, Anchor and there is another, Ballymore. And we consider they are a very good partner for us there. We had made last year our first deal about exploration. We increased it.

By the way, some of the -- it's not just acquiring some acreage, it's drilling because we plan to the first prospect together in '27. So for me, yes, it is part of the strategy. We like exploration. And honestly, our partnership with Chevron in the Gulf of Mexico is a good fit. And I think I recently had the opportunity to discuss that with Mike.

And we both agreed that we continue. And on the other side, by the way, you probably noticed that we have announced some JV in exploration with them in Nigeria, for example, in Africa, so where we are strong. So we try to combine our strengths in, I would say, our foundation territories where we are good together in other. And as we have both considering the exploration as an engine for future growth, I think there is a good alignment between both companies. And so we'll -- if we can do more, we'll continue to do more. So that's the idea. But the question again is completely there in the US Gulf, US Gulf of America is okay.

Jean-Luc Romain, CIC CIB.

It's aboutman offshore wind. It looks like Germany is relaxing its stance of renegotiation of conditions to develop acreage there. You took large positions two years, two to three years ago. And I was wondering what your willingness is there?

Okay. I mean, honestly, they are contradicting news from Germany about what they want to do, what they don't want to do. It is clear that today, the merchant offshore wind in Germany is a challenge, to be honest. We are not the only one to explain that. Maybe we are optimistic.

But it's a challenge because, in fact, customers are not -- because first, the costs are higher. I would also say that the connections are longer. So the German government, which is a commitment to deliver some connections to the concession does not fully fulfilled its commitment. So that's a debate between our companies and the government. So we'll see what they mean on our side.

I think we need to -- we are evaluating the situation. We have different concessions. We have some which have been acquired with a cheap price. On which we intend to continue to work. For the other ones, we'll have to evaluate the impact.

At the end, the objective is to make, I would say, some affordable electricity for customers. So if it's not affordable, I don't know why we should invest. So that I would say, the condition of any investment by our side. By the way, you will notice in our accounts of the fourth quarter or the third quarter that we have made some write-offs on some of these concessions just to reflect the fact that today on some of them, we don't see how we could monetize them in a profitable way for us and for the customers. It's not true for all the German concessions. So I will not be more explicit. That's the way we consider this business. Thank you. Thank you to all of you. I think we have done.

There is no more question. So in such case, I would like to thank you for listening. I know that you will all rush to the call from a competitor, which is a good friend as well. So I wish you the best. And I think our next meeting will be, in fact, together in February, in London, where we'll announce the results for the full year, the fourth quarter and return to shareholders to meet the 40%.

Thank you.