TotalEnergies SE

Ladies and gentlemen, welcome to the Total Energy's third quarter 2024 results conference call. I now hand over to Patrick Pouyanné, Chairman and CEO of Jean-Pierre Sbraire CFO, who will lead you through this call. So, please go ahead.

Good morning, good afternoon everyone. Patrick Pouyanné here together with Jean-Pierre. Nice to be with you again after seeing you many of you in person that are invested in New York area this month. I just spent the last three weeks in road shows. I would like just to share with you that we got the constructive feedback from the investors on balance strategy and the level of understanding of our growth profile on both pillars, oil and gas, With the quality and depth of our extreme portfolio on one side, but also on the other side, the integrated power is now, I would say, better understood on both sides of the Atlantic. As discussed at the Inverse today, the clarity, consistency of our strategy must remain our priority. Discipline on cost, keeping a low break-even portfolio. And a strong balance sheet supporting attractive shareholder returns are fundamental principles which allow the company to be resilient through the cycles, especially when we are entering into an increasingly volatile and uncertain environment like what we have seen during this third quarter. I will not be longer, and I will hand over to Jean-Pierre to discuss the details of the three-quarter financials. which I think are proving also the resiliency of our integrated model in a challenging environment for both oil and refining margins. And then we'll be happy to answer to your question during the Q&A.

Thank you, Patrick, and good morning, good afternoon, everyone. This quarter, we faced a more challenging environment with refining margins sharply deteriorated, with the European refining margin marker down by 66% quarter to quarter, lower than our break-even at $25 per ton. Regarding the upstream environment, Brent decreased by 5% quarter-to-quarter to average $80 per barrel, while the company's average LNG price decreased by 6%. In this context, the company reported adjusted net income of $4.1 billion on the quarter and of $13.9 billion over the first nine months of the year. Profitability remained robust. We returned an average capital employed for the 12 months ending end of September at 14.6%. Moving now to the business segment, starting with the first pillar of our balance strategy, the hydrocarbons. First, regarding oil and gas production. During the third quarter, production was 2.41 million barrels of oil equivalent per day, within the guidance range of 2.4, 2.45 million barrels per oil equivalent per day. We continue to see good performance from project ramp-ups, mainly Merutu in Brazil, which partially offset unplanned shutdowns in Ictis Energy and security-related disruption in Libya. In addition, during the third quarter, we achieved first oil at the high-margin encore project in the Gulf of Mexico in the U.S., and first gas at the Phoenix field offshore in Argentina. We expect production for the fourth quarter of 2024 to be between 2.4 and 2.45 million barrels of oil equivalent per day, benefiting from the end of security-related disruption in Libya and yesterday's startup of the Meru Free project in Brazil that compensates for several plant shutdowns during the fourth quarter of 2024. Exploration and production performance continues to be strong. We've reported adjusted net operating income of $2.5 billion, stable cash flow of $4.3 billion, and an attractive return on capital employed of 15.6%. On the project side, earlier this month, the company and its partners sanctioned Grand Morgue projects, a large 220,000 barrels per day SPSO located offshore Suriname, with estimated recoverable oil reserves of more than 750 million barrels. This low-cost, low-emission development was sanctioned one year only after the end of the Brazil, and is designed to accommodate future time opportunities to extend the production plateau. Grand Morgue is a company fixed major oil and gas FID of 24, all of which de-risk your medium-term production growth objective of 3% per year through 2030, which ultimately translates into growing shareholder distributions. Exploration and production AC 932 OPEX per barrel equivalents remain best-in-class at $4.9 per barrel for the first nine months, 24, compared to our objective to be below $5 per barrel. Moving to integrated energy. First, on the results. Hydrocarbon production for LNG decreased 7% quarter to quarter, primarily linked to unplanned maintenance on interest energy. On the other hand, LNG sales increased by 8% quarter to quarter in the context of seasonal inventory replenishment. Integrated energy adjusted net operating income was $1.1 billion in the third quarter. Results primarily reflect lower LNG production, And in addition, gas trading did not fully benefit from markets characterized by low volatility. Cash flow was $0.9 billion due to the timing effect in dividend payments from some equity affiliates of around $200 million. Looking forward, given the evolution of oil and gas prices in the recent months and the lag effects on price formulas, Total Energy anticipates that its average LNG selling price should be around $10 per million BTU in the fourth quarter 2024, slightly higher than the $9.9 per million BTU in the third quarter. During the third quarter, Total Energy strengthens future cash flows by signing several medium-term sales contracts in Asia, bringing Total AGM LNG contracts signed year-to-year to 4 million tons. In addition, we enhanced integration along the gas value chain by supplying low-cost upstream dry gas supply in the Eagle Falls in Texas. Moving now to integrated power. As a result, the company continues to deliver on its targets. For the third quarter, adjusted net operating income remains close to $0.5 billion and cash flow above $0.6 billion. Year-to-date Adjusted net operating income totaled $1.6 billion, up 21% year-on-year, and cash flow totaled $1.95 billion, up 35%, and in line with annual guidance of more than $2.5 billion, contributing to the resiliency of the company. In addition, we have extended our track record of returns. We returned average capital employed for the 12 months ending end of September, close to 10%. TotalEnergy achieved several milestones during the third quarter, first one being the startup of two giant solar farms in the U.S. with battery storage in the fast-growing haircut market in Texas, where we already have all the necessary building blocks that define our differentiated integrated model. We closed on a strategic CPVT acquisition located in the deregulated UK markets that complements our existing intermittent renewable assets. And lastly, we strengthened our partnership in both India with ADENI and in Germany and in the Netherlands with RWE in offshore wind. In downstream, third quarter adjusted net operating income totaled $0.6 billion and cash flow totaled $1.2 billion. with marketing and trading activities partially compensating for the very sharp decrease in global refining margins in Europe, down 66% sequentially, and the rest of the world. In refining and chemicals, the company's European refining markets fell to $15 per ton in Q3 due to normalization of trade flows after the Russian ban and ample supply related to recent capacity increases. Currently, it is close to $25 per ton. This indicator, $15 per ton, is lower than our break-even at $25 per ton, and we suffered as well with some incidents in some of our refineries. For the fourth quarter of 2024, the company anticipates refining utilization rates will remain above 85%, with a turnaround planned at Lerner Refinery in October. Marketing and services results remain strong for the third quarter, with adjusted net operating income of $0.4 billion and cash flow of $0.6 billion. At the company level, and to wrap up, in the third quarter, we reported $1.1 billion of negative adjustment to net income related to impairments, these impairments being linked to two events, The first one, the Chapter 11 bankruptcy filing of SunPower in the U.S., and the exit on blocks 11B, 12B, and 567 in South Africa. After the BILT reported in the first quarter, the first working capital release was reported during the second quarter, and a new release of $0.4 billion was reported this quarter. And we anticipate that working capital will continue to reverse in the first quarter. A new release of $2 billion is anticipated for the first quarter, 2024. As I was saying in the introduction, profitability remains robust. We return on average capital employed at 14.6%. Capital discipline is strong. We confirm 24 net investment guidance of $16 to $18 billion. Lastly, we continue our track record of strong shareholder distribution. Buybacks are consistent with the company set to execute yet another $2 billion in the first quarter, in line with the objective of $8 billion for the full year 2024. Dividend growth is healthy, with the third interim dividend up nearly 7% compared to 2023, and up 20% compared to pre-COVID levels. We stop here, and we've With that, Patrick and I are available to answer your questions.

Thank you, ladies and gentlemen. We will now begin the question and answer session. As a reminder, if you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking a question. If you wish to consent your request, please press star 2. Once again, please press star one if you wish to ask a question. The first question is from Lydia from Berkeley.

Please go ahead. Thank you, and good afternoon, and thank you for the presentation. Two questions, if I could first. The first one on cash flow. If I look at the cash flow in the quarter, it's just under $7 billion X working capital. At an oil price of what was effectively $80, that's not actually enough to cover CapEx dividends and buybacks. So is that just a specific costly feature or is cash flow actually starting to lag behind your expectations? And then secondly, very different topic, but we have started to see some transactions in the Vaca Muerta in Argentina. Can you talk through what your plans are for Argentina and what you think the opportunity there might be? Thanks.

Under cash flow, I think Jean-Pierre mentioned in his speech that there was a lag effect on some SMEs between the results and the cash dividends, mainly LNG SMEs. So it's why it's affecting the integrated LNG cash flow in Nigeria and Qatar. But I think this is not... something which should be reversed. In fact, there is no fundamental reason to have such a difference. It's just a quarterly effect. But I would say no more, no more, no specific point behind this one, I would say. On the second question, yes, I learned that. And we have quite a lot, as you know, of accuracy in Argentina. We know that we manage that quite cautiously. We just recirculated CAPEX cash flow. We mainly produce gas. We have some accurate exactly like Exxon in the oil window, which until now we did not develop. In fact, it's a question of CAPEX. We know it's a question mark, by the way, in our company to know if we move from allocating CAPEX more on the oil window and less on the gas. But that would require some investment. So we are evaluating both options. Having said that, we do not intend, as long as I would say, you know, Argentina is a specific country where you cannot repatriate dividends freely. So as long as it remains the same, as I explained to the Argentinian president when I met him last month, we want our money back. So if we will not invest more, as long as we don't see the freedom to repatriate dividends or Again, we have a large portfolio. We are evaluating options in that country, but that's what I can tell you. And we will, of course, analyze the different options we have in that view.

The next question is from Michele De La Vina from Goldman Sachs. Please go ahead.

Thank you very much. I had two quick questions. The first one, I was wondering if you could update us with progress with your Uganda project, one of the giant startups we've got in the relatively near term. And also in Mozambique, we've had the elections. Does this effectively bring you one step forward to restarting that project? And then secondly, I was wondering, with COP29 coming up in Baku next month, if you had any expectation of what you think could be some of the low-hanging fruit or some of the wins in terms of changes to the global policy there. Thank you.

Okay, thank you, Michele. Uganda is progressing as per plan. We intend to start the production by mid-26. The The drilling is positive, I would say. I mean, the news from the reservoir point of view are globally, I mean, positive. In fact, we have no... So I would say it's progressing. And the pipeline itself is being started to be built and laid. So I would say we are on the way to deliver this important project, as you said, not only in terms of production, but also in terms of cash flow for the company. It's quite a sizable investment. So that's where we are on Uganda. On Mozambique, I would say we need to, I mean, again, you know, there are different aspects in Mozambique. One of them was the security. On the security side, I would say we are... It has progressed. Of course, the fact that there will be a stable political power in Mozambique is important for us. So we are following the different news from there, and we intend to visit the country when it will be ready. But I think it's, of course, positive. The more stability in the country will come, the better it is for all of us. Having said that, we are more focused on our side in Cabo Delgado. And in Cabo Delgado, good news from the election process, but it was quiet. There were no events during that period. So I would say from this perspective, for me, it's positive. But the assessment there on the security side, fundamentally, that we could restart those projects. With the contractors, we worked hard. Everybody is there. But as I told you, I think, last time, the last point on which we are working, and I hope we have good news, is that... We are working on the financing of the project. You know, there was a big project financing package which was signed, in fact, executed in 2020, 2021. We began, by the way, to execute it in 2021 before the fourth measure. All the credit export agencies have done due diligence on the project, and technically it's okay. Now we are waiting for the different green lights, in particular from... I would say, some G7 credit agencies, and we are working for them. So from my perspective, I would say we are on the right track, but of course this is fundamental to have all the financing in place before we restart the project. That's the last point on which we work. On COP29, honestly, I don't see a lot. I mean, I will myself be there because, you know, I am... one of the three champions of the oil and gas decarbonization charter, together with Sultan Al-Jubeir and Amin Nasser. So we have an event there. I would say, by the way, it's an interesting collective move for the industry. We have engaged with 52 companies, a lot of national oil companies, and it's an interesting, I would say, moving forward to put in place initiatives With these national companies, the same type of reporting framework, but the one we have, and it's a way to progress, to share also a lot of experience, and short of experience in terms of abating methane emissions, which is one of the objectives. So I think that is positive. On the COP29, I'm not partly, I mean, I'm not myself, we are not, I would say, part of the discussions. According to the news I got, we don't expect much new things. One of the key chapters on which we would like to see progress is on the question of the carbon credits, if any more, Article 6. Because it's important in order to invest in this type of credits to have a sort of strong framework which would be validated by the UN and the Global International Committee would be good, I think, in order to make these investments, stronger investments So that's, I would say, the main expectations on our side.

Thank you.

The next question is from Matt Loftinger from G.P. Morgan. Please go ahead.

Hi, Jens. Thanks for taking the questions. Two, if I could, please. First, just coming back to your earlier comments on cash flow generation in the quarter, I mean, obviously, CFFO can fluctuate and there can be phasing effects quarter on quarter. I just wonder if you look at year-to-date, sort of the nine-month performance, can you talk about an underlying cash generation issue? over the course of 2024 and perhaps how it compares to your beginning of year expectations on an underlying basis. And then secondly, the capital frame was made very, very clear in the beginning of October with Invest Today. Given though short term macro volatility to the downside as well as the upside, could you talk about where the threshold sits in terms of when TotalEnergies would look to activate some or all of the 2 billion capex flex that you talked about. Thank you.

Okay. First, on the cash generation, I would say on the cash flow after nine months, we are at $23 billion next to 23. So it means we are today at the third last quarter was around $7 billion. So it's around $30 billion we could land at the end of the year. which is, in fact, we are more in line. We were at 31, 32, higher expectations on one side with the refining margin. So for me, we are in the ballpark. And I would say from this global perspective, it does not change. All the guidance we gave you at the last CMD in New York, including on the share buybacks, I would say I'm comfortable. We are comfortable. We are on the track that we were anticipating. So I see no impact whatsoever. We are, from this perspective, so let's consider we are there at around $30 billion. Can you talk capex? You know, the capex for me, $2 billion, it's not at $70, but we'll change our strategy, you know, policy from this perspective, $70. When we speak about short-term, short-cycle capex, These are capex, which at $70 will give us a payback, which is quite quick, in fact. So for me, the change, it's only if we are going to $50, $60 per barrel that we could consider activating part of this flexibility and arbitrating some of these short cycle capex, because the payback from these additional words will be longer. So I see no difference from between 70 and 90. The market today seems to be down to 70. But again, from this perspective, the guidance we gave you at the last TMD, you can consider them good. By the way, I remind you just to correct it's 1718 not 1618 for the year 1718 billion dollars for the year 24 and for next year we told you it will be in the range of 1618 and you have the 18 billion dollars of organic capex so super thank you Patrick the next question is from Irene from Bernstein please go ahead

Thank you very much. Good morning. My first question on refining, obviously a very weak quarter. Patrick, you have said before that you're not positive on the business, but do you see grounds for optimism that as OPEC Plus starts returning 2.2 million miles a day to the market, margins could strengthen meaningfully from the current $25, which I believe is your break-even level, and then My second question on LNG, recently Total was quoted in the press as expecting the next wave of capacity to be delayed by two years, which is obviously very material. You're a key participant to that global increase through your strategic focus on LNG. Can you share with us where you see the delays, which big projects are driving this view, and In that delay scenario, where would you expect ETF next year, please? Thank you.

Okay. I don't know what is... And first, refining. You know, refining, the average margin on... You can take different metrics. It's around $35 per ton on... 2013-2023. And by the way, this is the planning assumption we use internally on the long term. It's $35 per ton, which is higher than the $25 today. And that's why we are working hard to have this break-even going down to $25 per ton. I know that I'm moderately optimistic about these events. I think we benefited from two years where During COVID-19 2021, there was a huge acceleration of some shutdowns of refinery in the Atlantic Basin, on both sides, by the way, in particular on the American side, in the Caribbean Islands, in the U.S., a lot of conversion to biorefinery. Then you had the dislocation of the market because of Russian flows, which has added, I would say, some dislocation and some pushing the margin up. I think since, of course, like always, when price margins are good, people stop continuing to restructuring, in particular in Europe. We've even seen some few small refineries which were supposed to be shut down, which was maintained. And then, on the top of it, you add some new refineries, which have started in particular in China, which have added an additional capacity. The Chinese were supposed in their policy to shut down some what they call the T-poles, the old small refineries, but the T-poles are still cooking, I would say. And that means that you have quite a lot of supply at the same time. And today, in fact, we are also facing in Europe the fact that some flows are coming, some products are coming from the U.S., which can, because the Russians products go to South America, U.S. coming to Europe. And Europe, last but not least, as you know, industry demand in Europe is not very strong today. So that means that we are back, I would say, to the traditional cycle where I, we stopped, I mean we, not total energy, but the industry stopped, I would say, restructuring to capture the good margins, and I think the hard times are just there to come back fundamentally What was true before is still true today. You have too many small refineries in Europe, and everybody has to do his job, I would say. One way, as you know, is to transform this refinery in biorefineries, because at the same time, in Europe, we benefit from regulations which push biofuels for having a better demand for biofuels for regulation. So I would say that from the optimism, I'm moderately optimistic. I would be more optimistic if I see more, I would say, announcements about shutting down refinery, but it takes time. It takes time. So let's see, $35 per ton are for me a good long-term plan, and then it's volatile, so I hope we will capture more in the future. But like for oil price, you know, it's difficult to guess about it. LNG, I don't know who has said two years. No, I think we are very clear. I was very clear in New York CMD, I told you that we were thinking that the wave will begin, not 26, but 27. I think nobody had ever spoken about 25, we don't see a big additional supply in 25, it was never mentioned. There was a debate between 26 and 27, and we are just reading the news, you know, and there are some projects in the US which have been delayed for different reasons. So I would say on my view, we stick to, there is no additional comments to the one we have done. The wave of additional capacity, 10% per year during three years, will for us begin, maybe it's second half 26, but 27, 28, 29. So for 2025, I would say we are expecting TTF It's seasonal, so it's the average on the year. The average today on TTF is around, I think, $10, $12. No, today we are more on $12, $13. I have the NBP of 12.4. So TTF must be more or less at the same level by NBP. So we anticipate for 2025 something in the same range. I think I would say around an average of around $12 per million BGU. Because, again, we don't see in 2025 any... additional capacity, which would suddenly change the fundamentals of, I would say, a market which is still in the tension. And then we'll see by 26, and of course we will follow carefully all the news of startup of delays along the year 2025. So again, I'm not sure. One year, 27 yes, two years no, and 25 should remain in our view today. the same type of environment that we have benefited in 24. So positive for TotalEnergies as a big energy player.

The next question is from Christopher Couplan from Bank of America. Please go ahead.

Thank you very much. Good afternoon. Just two questions on renewables, please, from me. I want to double check, Patrick, if you could give us a little more detail on how you feel the current market sits. I think since we saw you in New York, you've farmed into an RWE project. Is it easier to farm in these days? How much more difficult is it to find partners for farm downs that you're looking for in parallel on other projects? And maybe related to that, please let us know what you think of making a corporate acquisition, as Equinor did, becoming a 10% shareholder of Orsted, and whether you would contemplate anything similar for Total. Thank you.

The first one is quite easy. You know, we had an option which was negotiated with WWE because, as you've noticed, we made a farm in their Dutch offshore runs. in connection with our will to decarbonize our Zealand refinery for green hydrogen. So that was part. We negotiated an option. RWE was efficient, I would say, and successful to get access to offshore wind licenses with a low cost of entry. So it would be strange for us not to exercise our option. because obviously they work well, we benefited from it, and it's good for us. That could let us, of course, as you know, we are trying more to be willing to scale these offshore wind licenses. By the way, working closely with AW is also a good option for us and for them to go globally because we need two main players. So I think driving down the cost will be by, I would say, scaling up these developments together. That's something we can't have in place. And for us, I would say we have more options for wind Germany, and so we will see in which order we must develop the different package. But again, it was a good opportunity, and the answer from this perspective was obvious to us. I don't like to comment the move of my competitors. I respect everybody has its own strategy. on Norwegian fronts, are very focused on offshore winds, so they have probably good answers. What is clear is that, in my view, just to comment, and know we have been consistent, to become a minority shareholder of a competitor without, on our side, an industrial strategy, we've never done it. And so when we went to VivaDani, you know, yes, we are a minority shareholder of Vanetti Green, but we developed, on the same side, some GV to have access to some industrial... assets. So that's the way I see this type of leverage. It's probably, I don't know, I did not study carefully the case of Orsted and Equinox, but I think I respect their decision. And again, on our side, we think that we can develop organically some efficient offshore wind assets. And that's why we have done it, why we I would not have considered such acquisition, but again, I respect their decision.

Understood. Thank you.

The next question is from Martin Retz from Morgan Stanley. Please go ahead.

I wanted to get back to the question that Irene also asked about, which is refining margins specifically in Europe. Because there is quite a lot of indication that there are some economic run cuts in the European refining system. But looking at the data that you reported today and also the guidance for utilization in the fourth quarter, I'm seemingly not in the total portfolio. So I just wanted to confirm, margins have declined quite a bit, but they're not low enough for you to consider any economic run cuts, right? That was the first I wanted to ask. And the second one is about the balance sheet. Last quarter, gearing 10% during the earnings school. You talked about the sort of underlying level of about 7% to 8% if you cleaned up for a few noisy items. We're now at 12%. What explains the difference between the sort of 7% to 8% that was mentioned last quarter that we're now at, and how do you expect that to develop over the next one or two quarters, please? Thank you.

Okay. Honestly, I'm not sure we are big enough to consider ourselves cutting grants just to please our competitors. That's a type of strategy which is not an opaque of European refiners. We are today at the break-even, and I think it's something which, because when you have quite high fixed costs, And so I compare that more on the variable, it's more a question of variable, do we cover our variable costs? You know, break-even is calculated in terms of fixed plus variable costs. As long as we are, the margin is better than the variable costs, it's better to run the refineries in order to cover part of your fixed costs. So we are largely covering our variable costs, so that's it. It's a simple economic theory, but no, we are not there. The question will be more for us, more structurally. And as you know, we have already transformed some refineries into biorefineries in 2015, in 2020, as we have been always clear that we are working on the follow-up of these ones, just on one side to capture the opportunity of the European biofuel markets on the other side, because... Except the last two years, generally, it's economically marginal. So this is the most important question for me. Our instructions to our teams is make the best use of your assets. And as long as you cover your valuable costs, obviously, you have to run in order to cover part of the fixed costs. Second question. No, I mean, let me clear. I don't know if the 7%, 8% was last year. We have more. You know that we have explained to you there is a gearing of different aspects. It's a little high today. I think we should be back in the range that you mentioned, 10% to 12% by the end of the year for different reasons. For this quarter, as you've seen, we still have, and I think Jean-Pierre was clear in his speech, We anticipate a working cap release of $2 billion for the next quarter, which is in line with the guidance we gave since the beginning of the year. We had a big cash out at the beginning of the year, more than $4 billion, if I remember. $2 billion were perfectly linked to exceptional events of last year, of taxation events of 2023. and over 2 billion should be coming back in the balance sheet before year-end. So I know that all the businesses are working on it, so I would say this is part of it. Then the other part of it is that, as some of you have noticed, probably the capex were high because this quarter we have more acquisition than sales. The inorganic was high, but it will be rebalanced. It's a question, again, of phasing the diverse months and years. As you know, we are expecting some renewable divestments because it's part of the model which should be concluded. And in this type of business of M&A, there is a lot of things rushing, lastminute.com, you know, the last quarter. And we don't push them necessarily just to finalize all these, close the deals before 30th of September, 31st of December. But it's not only total energy, it's a common practice. So I would say my view is that we should come back to something like around 11%, 12% by the end of the year. This is what we can anticipate if, of course, we remain in this type of price environment of today. That's what I can tell you. But again, I know you, Martin, this type of hearing was anticipated earlier. At the board level, when we discussed about shareholder returns and we gave you the guidance for next year, about $2 billion per quarter for share buyback and dividend increasing at least by the buyback of 23%, which is at least by 5%. It was anticipated this type of hearing level.

Wonderful. Thank you.

The next question is from Doug Legate from Wolf Research. Please go ahead.

Good morning, everyone. Patrick, I know you've been asked extensively about refining this morning, but I want to ask the same question a little differently. Some of your peers have started to consider shutting refineries when they have a major capital event like a turnaround. And as we appear to be coming into an extended downturn, let's assume, for refining for the time being, how do you see the portfolio today? I understand the break-even is $25, but are there any assets you would consider rationalizing at this point if this weakness continues?

Again, you know, we've done it. And we've done it with Lamed in 2015. We've done it with Grand Prix in 2020. And it's quite clear that when we do it, we try to look to the agenda of the shutdowns to avoid to spend a lot of money on the refinery and to shut down one year after. So that's part of the turnaround of refineries. It happens every four or five years. Some of them, by the way, in our case, are making turnarounds every two years. Some of them are more longer cycles, four or five years. So that is taken into consideration. But it's not because of the turnaround, which, again, We will avoid, we will make a decision before to spend it, for sure. But I would say, again, more the way we have selected Lamed or we have selected Grand Prix is more, in fact, the structural, I would say, weakness or interest to transform them because of their location or because of their markets, et cetera. So when we think to this type of, you know, we have six, seven refineries, I think, today still remaining in... in 1, 2, 3, 4, 5, 6, 6 refineries in Europe. We know each of these assets. We know their strengths. We know their weaknesses. And we will, if we have, and as you know, we have been consistently, my view is that we need to transform them one after one. And at each of these events, it's quite a big event in terms of not only reinvestment on the platform to transform, but also in terms of social impact. it's better to face them rather than to wait 2035 and the decrease of the gasoline and diesel market in Europe, which will happen because of the decisions of the EU about the EVs and all that. So yes, we will continue to plan it. And of course, we will avoid to wait to spend the money on the platform to just after announce that we will shut down. But again, for me, it's not because this strategic thinking is not linked to the low cycle of today. We have prepared it. Since we have a large Grand Prix, I would say we are preparing the next one. The question is then to what are the different opportunities and to be sure that we are and the markets are moving from this perspective, you know, including these biofuel markets in Europe. is moving. Today it's facing some oversupply. So this type of thinking could affect us in our calendar. So we are working on it. But again, this is also important in my view. Normally in a market economy, you have what I would say is a cost-merit curve of different assets. And when the margins are low, the first ones to shut down are the ones with higher breakeven, I would say. So as we have good assets with low breakeven, I'm expecting others to move to shutdown before us. Normally, it's the way it works. Otherwise, so we'll see. And having said that, again, you know our ambition, I would say more on the opportunistic, on the opportunity side, the positive side, you know that we consider that this biofuel market, the soft market in Europe with a mandate of 6% is giving good opportunities for brownfield projects rather than for greenfield ones. We exclude greenfields, and we have the ambition to continue to benefit from this market.

Thank you for the full answer, Patrick. My follow-up is a quick one on Suriname. Sadly, I was unable to be in person in New York when you presented the strategy update, but you did talk about Suriname sanctioned on a four-year plateau. but with tie-back opportunities. Since then, your partner has been suggesting the plateau could be extended as much as to eight years. I wonder if I could ask you to offer your perspective on that.

We are the operator of the project. So what's your view on the long-term plateau? I stick to what we told you. We are the operator of the project. We said that this plateau is designed for four years. We also explained that we have selected quite a high plateau level because we consider that Gran Morgo could be the hub of more tiebacks. I'm unable to quantify it because most of these tiebacks have not yet been drilled. So let's drill them before to speak about the duration.

Terrific. Thanks so much.

The next question is from Viray Phulkathara. from Bank of America. Please go ahead.

Hi, thanks for taking my question. I just had one related to going back to the CSFO again. At the start of this year, you gave CSFO guidance, which looks like it's something close to 34, and the macro environment that you showed then versus what we've seen is not that different. Obviously, refining has been weaker, but is it possible to help me bridge the gap between the 34-ish billion that you maybe originally envisaged, and the 30 billion or so that you mentioned today. Any moving parts there would be helpful. Thank you.

I don't remember 34. I had 32 in mind. But I would say clearly along the year, the gas price was lower than expected during the first half of the year. I think we have been clear. We went down under $10 per million BTU during the first half. The European inventories were completely replenished. It has a seasonal effect. We are back since this summer to $12, $13 per million BTU, more in line with our assumptions. So I would say there is $1 billion somewhere for me, which is linked to this gas. The market has been less volatile, and it's true that in a less volatile market, our trading business has been a performance which was... Very good. More than good. Super good. Excellent in 2022-2023. Benefiting from big volatility. When the market is quite stable, it's more difficult. I would say there is $1 billion probably out of this $1 billion, $1.5 billion out of this gas trading and low gas pricing. The other part will come from this refining business. Well, I think we're losing... I would say, I don't know, I don't have the figures in mind, $500 million or less. I think the best for, we will reconcile all that by the end of the year because the year is not yet finished in any case. So I would say that's the main, I would say, that's the main elements I have in mind. But what I suggest, Biraj, is that, again, I'm trying, my team's trying to calculate quicker than me, so I'm but they are a little slow. So the best is that I think you can, they will give you a call to tell you, but again, I don't have all the math here between the 34 and the 30. Okay.

Okay, that's fine. Thank you.

So gas and refining. Okay.

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

Yeah, thanks very much. Nice to talk to you in a couple as well, if I might. I want to focus on Nigeria for a moment, if I might. Firstly, Patrick, can you just remind me where we are around the sale of the onshore assets to Chapal? Is that expected to complete? Where are things with the authorities?

Just in the commentary. And also...

Could you make any comment on Nigeria 7 and progress in terms of development and timing and just generally on gas flows into Nigeria LNG and how those have been progressing through this year and in my opinion play to your offtake and then secondly just if JP perhaps could comment at all on the write-offs that we've taken you know this course of a billion or so of of asset write-down, which looks very much as though it's dealing with sun power, but just explain to me. That's it. Thank you very much.

Okay. I think we have progressed. We received some approval from NNPC. I think recently the regulator said that we should have a green light, so we are working on it. No, just we are not in the same position that some of our peers because we are not operating and we are in a non-operating position. So I think it's easier for the authorities to evaluate the quality of the buyer because we are non-operator. So we transfer and we have a limited share. We have 10%. So the 10% is limited share, non-operated positions. So, of course, in terms of evaluation by the regulators, it's easier probably to... to approve, and we have our buyer, by the way, has been already approved recently in a deal on an offshore asset, an unoperated offshore asset, so it's a buyer who is well-known by a few authorities, so I do not anticipate difficulties on it, and we have, so we receive a process to follow, and we are following that carefully, so that's a point. On 27, as you know, we have been Working hard for the last year in order to obtain the right terms to be able to develop some new gas projects in order to fill this train 7. Because, as you know, we have already some difficulty to supply all the gas to the first six trains. So I've been quite clear myself, but I think our colleagues as well, our peers as well, with the Nigerian authorities, that it's time to accelerate the sanctioning of gas projects in order to fill these trains. We have got some improvements, in particular on the transfer gas price between the upstream and the downstream. Also, we have sanctioned the first project, UBETA, which has been sanctioned this year, and which is dedicated to fill these trains So TotalEnergies will be in line with its commitments in terms of supplying the first seven trains. We are working on another one, which is called IMA, which is a small, very quite low-cost gas cell very next to Boney Islands. So we are working on it, trying to sanction that in 2025. So it's a good opportunity to monetize gas reserves The authorities have enhanced, I would say, the global package to valorize fiscal leave with the gas reserves. So things should be aligned. Again, Nigeria is not an easy one, an easy country. But at the end, we managed to make good projects and profitable projects. So I'm positive on that. The write-off, I think, Jean-Pierre, there are two parts. One was linked to SunPower. The company went to Chapter 11, so we had to write off what was remaining because the capital employed. And another part was linked to the decision about South African assets, where we made some discoveries, but the monetization of these gas discoveries was too difficult. In fact, there is no gas market. The gas infrastructure is very limited. The possibility to go from gas to power is also very complex, because you can read in newspapers the situation of ESCOM in South Africa. So at the end, we decided that it was the effort, and we had some contractual commitments. So either we were moving on in development, or we were stopping using the assets. I would say that was also a question of timeline, which led us to take that decision. It's true, but by the way, just to remind you a long story on South Africa, when we took these licenses, it was not to discover gas. It was because we are looking for oil. Like today, we are looking for oil in the licenses we have in South Africa next to Namibia. So it's clear that oil is easier to monetize in South Africa than gas. So, in particular, when gas is not located next to customers. And most of the industries in South Africa are not on the coastline south of the country, but they are more in the northwest of the country, so a little far away. So, it has never been easy with the gas market there, and that's the conclusion. So, that's the two reasons why we make these two right of this quarter.

Can I just push you a bit more on Nigeria? If I think about the start-up of Train 7, what's your latest commentary on when you might expect that to happen? And secondly, gas prices used to be nominal, or nominal, very low, exceptionally low in Nigeria. Just some sense of what you're actually able to, or what price, should I say, what price do you need in order to justify an adequate return on the investment you're making? Yes.

So train 7 is expected to start up by 26, probably end of 26. That's part of the ones which are not, to come back to a question that I had before, that's one of the trains which probably will not be in advance, to be clear. Okay, so you can push it more to 26 to 27 rather than 26, to be clear. And by the way, as we are also developing the gas, we don't need to have the train ready, and so we try to I would suspend the capex according to also the feed gas. Okay? Yeah.

And price on gas that you're managing to get from the Nigerians to agree or NLNG to agree?

No, it's done. We have an agreement with them. We have increased and all the partners of NLNG have agreed that... the gas transfer price from the upstream to the plant will be higher, which is normal, you know, because initially, historically, when it started in 1997 or 1998, there was a big alignment between the supplier and the shareholder, the foreign shareholder, and the shareholder, in fact. You had 60% NNPC, and then you had the three major players, Shell, Total Energies, and ENI. which were on both sides. So, in fact, the transfer price was an issue for the only GV which was not participating to NLNG, which was, in fact, by that time, the ConocoGV. But along the years, as you noticed, and that was why it was critical to solve it, we had different views, the different partners of NLNG had different views on their commitments to develop upstream gas. So there was a point where... As soon as you don't have an alignment, we don't see why Total Energy should develop more gas than its share for the benefit of other partners in an energy. You know, that was not very fair. So that was the discussions, and we solved it collectively in the interest to develop more gas upstream. And, of course, that means that part of the margin is transferred from the downstream to the upstream in order to finance the development. That's quite clear. As we are on both sides, we are somewhere neutral, but it's not the case for everybody.

Peter, Patrick, thank you. JP, thank you.

The next question is from Kim Fustier from HSBC. Please go ahead.

Hi, thanks for taking my questions. I've got two, please. First on the outage at Ixis LNG. You've talked for some time about preventive maintenance to try and minimize any unplanned outages. Is there a way that this issue on the heat exchanger could have been avoided in any way? I also understand that ICSIS is expected to restart fully by mid-November, so should we expect a similar financial impact in Q4 as in Q3, so around $100 million? And then secondly, on net financial expenses, I've seen them tick up over the past two quarters. Could you talk about how your cost of debt is evolving as you refinance debt at presumably higher interest rates? Thank you.

I'm sorry, but I'm not in charge of all the exchanges of the company. And by the way, we are not operating XS. So something happened there. It has been solved. That's the point. And I think my people in charge of operations are drawing the lessons that... to avoid these type of issues. It's a big machine. It can happen. And I'm sure that our operator and my teams who are in Australia are working their best, doing their best to avoid these type of unplanned events. That's life, I would say. Financial impact on Q4, I think it has been solved, I think now. ICTIS has restarted, if I can link to my information. So it should be, the impact should be, it's not only $200 million. I don't know why you mentioned $200 or $300. I'm not sure it was so big as an individual, because there were different impacts on the cash. It's not only ICTIS. ICTIS is part of it. I don't have the ID. You have an ID, Jean-Pierre? No, I don't have the ID. Okay. Debt and interest rates. I will let Jean-Pierre, he's the expert of all this debt management.

For the time, I have a very good portfolio in terms of costs below 4% globally, so I do not see the reason why I should refinance. What we did, we made two insurance in the U.S. market, one in April and one in September, very successful because it was largely financed with very low maturity. So the strategy we continue to implement is to try to have longer maturity, 30, 40 years at attractive price. But once again, at present time, it's a very competitive bond portfolio.

Thank you.

Okay, just before we take this next question, I would like to answer to Biraj a little clearer, because in the meantime, the teams have worked. So if Biraj is still online, he will be happy. You are right, the 34 was expecting. We are more today at 30, 31 billion dollars expecting by the end of the year. So my doubt on the gas, the fact that the gas price was lower at 1 billion, The lower gas, trading gas and LNG gas is $1 billion. So compared to the year before. So it's $2 billion on the, I would say, gas and LNG as a rule. And it's $1 billion on the refining margins. So last $500 billion, I'm not sure to have the figures. But just to, I'm correcting, I can easily go from 34 to 31, let's say, and then... something which are different elements, but we'll come back to you next February with all the details, just to be sure that the elements are filled with everybody.

Henry?

The next question is from Harry Patrico from UBS. Please, go ahead.

Yes, everyone. Thank you for the update. Two questions, please. The first one, actually, just a quick follow-up on these comments around the CFFO generation in the year. I was wondering if the chemicals segment is also an area where you've seen lower cash flow than expected versus what you had at the start of the year through a combination of the macro and maybe slow ramp-up of Baystar or underlying performance elsewhere in the business. And then secondly, on the integrated power, Roche dipped below 10% this quarter. How quickly should we expect that, Roche, to go back above the 10% level?

Okay, the second one is quite easy. It's linked to the calendar of the farm downs. In fact, as I told you before, the farm downs, when you make it on the renewables, have quite an impact because, of course, not only... In terms of capital employed, you will not only eliminate the share of equity, but also the share of the debt. So it has a double effect. And so as the farm downs are planned by the renewable business unit in the fourth quarter, you can see some, I would say, a linear impact on the nonlinear impacts along the year. but we should reach the expectations. Again, 9.5, 9.6, 9.8, not a big difference. But that's for me the main explanation. It's more on the capital employee linked to the agenda of the farm downs. On the chemicals, I would say, you know, the chemicals, you follow probably some chemical companies. We are only at petrochemicals and polymers. The margins in Europe are low for quite a number of quarters. The global margins are not very big because, again, we face exactly like in refining, more Chinese capacities, I would say, on one side. And as we had quite a number of petrochemical projects, you know, in the U.S. in particular, there was a wave of ethane tracker, which was built from 2020 to 2023, and we are part of it. So quite a more supply linked to a low, cheap ethane cost, which is there. But most of these capacities in the U.S. were, in fact, invested to export. And at the same time, we've seen that the Chinese have been very active, in fact, to, again, be more self-sufficient. And so, of course, this is the point. So for me, margins are correct globally, but not very high. And so we are not in the high cycle. We are, I would say, in the middle-low cycle for chemicals products today. It's less critical than the refining dip. We are making some positive results, but it's not a beautiful market. But it's more, I would say, no chemicals. We are more downstream, and you have more of a global economic macro will affect them. So you can see the IMF expectations for the year are decreased quarter after quarter. So that impacts this type of businesses, I would say, in terms of demand. And so if demand is lower, of course, the margins are following.

Thank you.

The next question is from Paul Chang from Scotiabank. Please go ahead.

Thank you. Good afternoon or good morning. Patrick, just curious that for the integrated power Can you give us some maybe better understanding the contribution in your earning or CFFO between the gas-fired power portfolio and the renewable power portfolio? Thank you.

Yeah, and you forget and the customer portfolio because there are three segments of revenues or contribution. One is renewable power, the gas plant, and the customer plants, knowing that, as again, I'm repeating, it's an integrated business, so I will not make the money on the customer since I don't have the assets, but I'm making also additional revenue on the customer because I'm able to make this commercial business. I would say it's roughly three-thirds between the three parts, so one-third around renewables, one-third about the gas plants, and one-third about the customers, just to give you a rule of thumb in the way VCFFO is played today.

Patrick, can you give us an update on where we are on the Papua New Guinea LNG projects?

We have been very transparent in the market. We said that we interrupted the whole tender process because the capex was too high. We stopped, and together with our partners, we have reviewed some of the basics of design in order to streamline the projects. We have also been to a larger pool of contractors, in particular, summation contractors. According to my information, the re-tendering has begun. launched now the process to all the different contractors on the new scheme, which again, most of the scheme has been maintained, but we have some optimizations together with the partner in order to simplify and to make cheaper concepts. And we expect all that to be a process which is a little longer, so I'm expecting I think the offers by next summer 2025, I think it's... because it's a big process. And again, we have re-engaged. But the good news, I can tell you, is that there was quite a lot of appetite from contractors from the Asian world. So maybe the Western contractors were not so keen. But on that side of the continent, and, you know, either in India or in China, we can find some contractors. We had that appetite, which we are quite happy to be invited to contribute. And we have, of course, made all the qualification processes and and the teams are working very closely with them in order to have some good and competitive offers. So it's on its way.

And, Patrick, it goes according to plan. When is the first guess it's going to be?

I think it was written in our CMD booklet, so I don't have that in mind. Do you have the booklet? Yes. It's 2028. No, I'm not sure. It was written in the slide in the booklet, so I don't know everything by heart. Maybe my team can help me on this one. I will try to find it. One minute. This one? No? 28.

2028. OK, thank you.

The next question is from Harry Tarr from Berenberg. Please, go ahead.

Hi there, and thanks for taking my question. I just have one left, really. And that's just on the bio business, which I think you've referred to a couple of times. Europe is clearly incentivizing biofuel use, but there has been a lot of capacity that's been added. And if we see a lot more sort of brownfield conversions as well, are you confident that there's going to be sufficient demand in Europe and the U.S. to sort of soak up the demand? the available supply over the next two to three years. Clearly, we're in a little bit of a period of weak margins currently.

Thank you. This is exactly why I was answering to one of your colleagues previously, but when we speak about this type of transformation, we need to appreciate also the demand and supply. This market in Europe is completely regulated. It's coming from regulation. So why do we have today lower margins? It's because two countries in the north of Europe, Sweden and Finland, which were planning to have a mandate for biodiesel, which was above the minimum of Europe. So it was announced. It was planned. It was quite above. I think it was 30% instead of 10%. So some competitors have built some plants for producing HVO, renewable diesel. And unfortunately, a new government came in and they modified the mandate to come back to be, I would say, standard by a European mandate around 10%. So that created an oversupply and then the HVO margins have decreased. So that's a difficulty in that field. That's why when I was answering, of course, we are following that carefully because it's a niche, but the niche could be full quickly. I love the game of the airline companies who are pushing us up to produce more. In fact, they want us to have another supply, another price to go down. It's quite easy. They are complaining there is not enough stuff. Today, maybe we are in tension, but we might be on the other side. So we are evaluating all that because, of course, it makes little sense to invest and then to enter into another supply market. So we are evaluating that, and we are obliged now. I think the lesson we drew is let's be cautious. All these guys are announcing higher mandates, voluntary mandates. I'm only trusting the minimum legal standards mandates. These ones are strong because I don't think they will modify them but all these voluntary mandates are more questionable because again it's a question of competitiveness for our customers. So this is exactly the process where we are to evaluate properly I would say supply and demand in Europe like you have to do it in the US. In the US it's not exactly the same market because all the buyers from the US cannot move to Europe because the I would say the content and the regulations about what we call the biofuel in the South, in Europe, but in the West it's not exactly the same. So that's more protection from this perspective. But that's part of the work on which we need to be serious before we move on. There is also, as we told you in New York and other things to take into consideration, some new aviation regulation, which allows you to make some co-processing in some existing refineries. So, obviously, we have to evaluate. It's an opportunity for us, first, for our refinery to have better... to have better value for more existing assets. But we need to evaluate properly how much of this core processing could be used by the global industry in Europe because it will be a competitor to any greenfield or brownfield projects. So that's also part of the equation that we have to take into account.

That's great. Thanks for your answer.

The last question will be from Jason Gabelman from T.D. Cowan. Please go ahead.

Yeah, hey, it's Jason Gabelman from T.D. Cowan. I had two questions. The first on Russia, and if we're in a situation where the Russia-Ukraine conflict ends, I'm wondering how much cash is out there that you... haven't been able to recover between Yamal and Novatek dividends that you'll be able to recoup?

You know, I mean, first, I hope you are right in your assumption. The war will end not only for total energies, but more for the peace in our continent. And by the way, I think it would be important for the global economic mood in the continent if this war was ending. So No power on it. Now it's quite easy. The dividends of Novatec were representing around $600 million per year. So they are stuck. Most of them are stuck on the Novatec account, not on the SEA account, because Novatec has kept its dividend on its own account for us, in fact. So this represents around $1 billion, more or less, I would say. And then you have part of the Yamal dividends as well, which was at the beginning... We managed to get them, and we were transparent. We were, by the way, publishing it. Today, there is no publication because there is little or nothing, no dividends. So that means that you have probably another 500. So I don't know when it will end. So probably by the end of the year, it will be $1.5 to $2 billion of cash dividends, which are somewhere on other accounts, just to give you a magnitude of it. And of course, it's not a point.

Yep, that's helpful. Thanks. And then just going back or turning to CapEx, it looks like if you continue the pace of organic spending from 3Q that you'll breach the high end of guidance for the full year. And I know there's some inorganic acquisitions out there, Sapura OMV that hasn't closed yet. So just wondering as we or a month into the fourth quarter, how comfortable you are with the current CapEx guidance, and if some of these acquisitions close on this side of the calendar year, if you'll potentially breach the high end of the range.

No, we will not breach, okay? We told you we confirmed 17, 18 billion, so we confirm it. In fact, just to transparent review, the organic CapEx by the end of September were around $12.5 billion. So if I'm adding another 3 to 4, you will go to 16.5. There might be more M&A, more acquisitions by divestment, so I'm fine. I think, again, we are today in terms of global net capex at 14 by the end of this September. So that means we confirmed the guidance of 17-18. So you make the difference between 17-18 and 14. It makes 3 to 4 billion dollars of capex. which is quite consistent with what we just said. And it includes, to be clear, I include in that the possibility that we close this OMB acquisition in Malaysia. We'll see. I mean, it's a process which is not fully under our control. But this is where we are. So I think 12.5 organic, you can calculate. We are not at the high end of these 18 billion we mentioned for next year. We are far from it from this year in terms of organic. We'll be probably around 16. Okay?

Great. Thanks. Good.

Gentlemen, do you have any closing comments?

Yeah, we have some comments, so thank you for your attendance. Okay, again, I think the quota, of course, is lower than the previous ones. That's clear because we have been, I would say, at this refining margin. That's part of the integrated value chain. At the end, we are comfortable with the fact that we are on the right track to deliver. The global year will be in line with our expectations. We have confirmed with the board the return to shareholders and the strong return to shareholders guidance. Keep in mind that the year 2025 will also be positive. We told you in New York that we'll enter into a growth cycle, including on the hydrocarbon productions, more than 3%. And I can confirm you we had very good news yesterday afternoon. Meru 3 has started up, so the ramp-up will begin. We had Meru 2, which is going to its maximum. And so I can confirm to you that 2025 we'll have a production cycle more than 3%. So that also will help, of course, the resilience of the model. And so thank you again for your support and for having listened to us. And I hope we will have to meet you again in coming weeks.

Ladies and gentlemen, thank you for joining. The conference is now over. You may disconnect your telephone.