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Presentation

Operator: Ladies and gentlemen, welcome to the TotalEnergies Third Quarter 2024 Results Conference Call. I now hand over to Patrick Pouyanné, Chairman and CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

Patrick Pouyanné: 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 at our Investor Day in New York earlier 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 balanced strategy and the level of understanding of our growth profile on both pillars, oil and gas, with the quality and depth of our upstream 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 Investor Day, the clarity, consistency of our strategy must remain our priority.

Discipline on cost, keeping a low breakeven portfolio and a strong balance sheet supporting attractive shareholder returns are fundamental principles, which allow the company to be resilient for the cycles, especially when we are entering into an increasingly volatile and certain 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.

Jean-Pierre Sbraire: 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 breakeven at $25 per ton. Regarding the upstream environment, Brent decreased by 5% quarter-to-quarter to average $80 per barrel, while the company 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 with return on 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 balanced 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 Mero 2 in Brazil, which partially offset unplanned shutdowns in Ichthys LNG and security-related disruption in Libya. In addition, during the third quarter we perceived first oil at the high margin Suncor project in the Gulf of Mexico in the U.S. and first gas at the Fénix field offshore in Argentina. We expect production for the fourth quarter of 2024 to be between 2.4, 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 Mero 3 project in Brazil that compensates for several plant shutdowns during the fourth quarter 2024.

Exploration and production performance continues to be strong. We 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 GranMorgu projects that lost 220 barrels per day. FPSO located offshore Suriname with estimated recoverable oil reserves of more than 750 million barrels. These low costs low emission developments were sanctioned one year only after the end of appraisal and is designed to accommodate future timing opportunities to extend the production plateau. GranMorgu is accompanying six major oil and gas FID of 2024, all of which de-risked medium term production growth objective of 3% per year through 2030, which ultimately translates into growing shareholder distributions.

Exploration and production ASC932 OpEx per barrel equivalents remain best in class at $4.9 per barrel for the first nine months 2024 compared to our objective to be below $5 per barrel. Moving to integrated LNG, first on the results. Hydrocarbon production for LNG decreased 7% quarter-to-quarter, primarily linked to unplanned maintenance on Ichthys LNG. On the other hand, LNG sales increased by 8% quarter-to-quarter in the context of seasonal inventory replenishments. Integrated LNG adjusted net operating income was $1.1 billion in the third quarter, result primarily reflects 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 effect on price formulas, TotalEnergies 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, TotalEnergies strengthens future cash flows by signing several medium term sales contracts in Asia, bringing total Asian LNG contracts signed year-to-year to 4 million ton. In addition, we enhance the integration along the gas value chain by acquiring low cost upstream dry gas supply in the Eagle Ford in Texas. Moving now to Integrated Power. As a result, the Company continues to deliver on its targets. For the first 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 with return on average capital employed for the 12 months ending end of September, close to 10%. TotalEnergies 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 ERCOT market in Texas where we already have all the necessary building blocks that define our differentiated integrated model. We closed on the strategic CCGT acquisition located in the deregulated UK markets that complements our existing intermittent renewable assets.

And lastly we strengthened our partnership in both India with Adani and in Germany and in the Netherlands with RWE in offshore winds. 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 & 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 quality to recent capacity increases. Currently it is close to $25 per ton. This indicator $15 per ton is lower than our breakeven at $25 per ton and we suffered as well with some incidents in some of our refineries.

For the fourth quarter, 2024 the company anticipates refining utilization rate will remain above 85% with a turnaround planned at Leuna refinery in October. Marketing and services result remained 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 bid 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 with return on average capital employed at 14.6%. Capital discipline is strong. We confirm 2024 net investment guidance of $16 billion 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. Dividend growth is healthy with the third interim dividends up nearly 77% compared to 2023 and up 20% compared to pre-COVID levels. We stop here and with that Patrick and I are available to answer your questions.

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] The first question is from Lydia Rainforth from Barclays. Please go ahead.

Lydia Rainforth: 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 ex working capital and 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 quarterly 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.

Patrick Pouyanné: On cash flow, I think Jean-Pierre mentioned in his speech that there was – we had a…

Jean-Pierre Sbraire: A lag effect.

Patrick Pouyanné: A lag effect on some SMEs between the results and the cash dividends, mainly LNG SME. So, it’s why it’s affecting the integrated LNG cash flow in Nigeria, in Qatar. But I think this is not something we should be reversed. In fact, there is no fundamental reason to have such difference. It’s just a quarterly effect. So, I would say no more, no more. No specific point behind this one, I would say. On the second question, yes, I learned that. I mean we have quite a lot, as you know, of acreage in Argentina. We know that we manage that quite cautiously. We just recirculated CapEx cash flow. We mainly produce gas. We have some acreage 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 our fortunes. Having said that, we do not intend, as long as I would say, Argentina is a specific country where you cannot repatriate dividend freely. So as long as it remains the same, as I explained to the Argentinean 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. So 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 my view.

Operator: The next question is from Michele Della Vigna from Goldman Sachs. Please go ahead.

Michele Della Vigna: 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 the 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.

Patrick Pouyanné: Okay, thank you, Michele. Uganda is progressing as per plan. We intend to start the production by mid-2026. The drilling is positive, I would say. I mean the news from the reservoir point of view are globally, I mean positive [indiscernible]. 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 we 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, as you know, we have different aspects in Mozambique. One of them was a security. On the security side, I would say – 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 your stability in the country will come, the better it is for all of us. Having said that, we are more focused on north side on Cabo Delgado. And on Cabo Delgado is a good news from the election process, but it was quiet. There was 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 this project with the contractors we worked on, everybody is there. But as I told you, I think last time, the last point on which we are working, and I hope we’ll have good news is that we are working with the difference on the financing of the project.

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 force majeure, all the credit export agencies have done the due diligence from – on the projects. 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. So that’s the last point on which we work. On COP 29, honestly, I don’t see a lot – I mean I will myself be there because, as you know, I am one of the three champions of the oil and gas decarbonization charter together with Sultan Al Jaber 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 with these national companies, the same type of reporting framework is the one we have and so we have to progress to share also a lot of experience and sort of experience in terms of Beijing methane emissions, which is one of the objectives. So I think that is positive. On the COP 29, I’m not partly – I mean, I’m not – 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 chapter on which we’d like to see progress is on the question of the carbon credit if any more Article 6, how can we – because it’s important in order to invest in this type of credit to have a sort of strong framework, which will be validated by the UN and the global – International Committee would be good.

I think in order to make these investments in the stronger investments in that field. So that’s I would say, the main expectations on our side.

Michele Della Vigna: Thank you.

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

Matt Lofting: Hi, Jean. Thanks for taking the questions. Two, if I could, please. First, just coming back to your early 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 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 at the beginning of October with the Investor Day, 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 we look to activate some or all of the $2 billion CapEx that you talked about? Thank you.

Patrick Pouyanné: Okay. First, on the cash generation, I would say on the cash flow after nine months, we are at $23 billion, next to 2023. So it means we are today at the third last fourth quarter was around $7 billion. So it’s between – 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 billion, $32 billion. We have higher expectations on one side with the refining margins. 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 on the last CMD in New York, including the share buybacks, I would say I’m – we are comfortable with – we are on the track that we were anticipating. So I see no impact from this perspective.

So let’s consider we are there at around $30 billion. Can you talk to CapEx? The CapEx for me, $2 billion, it’s not at $70, but will change our strategy, policy from this perspective, $70 when we speak about short-term – short cycle CapEx is our CapEx, which at $70 will give us a payback, which is quite quick, in fact. And so for me, the change, it’s only if we are going to $50, $60 per barrel, but we could consider activating part of this flexibility and arbitrating some of these short-cycle CapEx because the payback from these additional wells 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 the last CMD, you can consider them good.

By the way, I remind you just to correct slightly, Jean-Pierre, it’s $17 billion, $18 billion, not $16 billion, $18 billion for the year $17 billion, $18 billion for the year 2024. And for next year, we told you it will be in the range of $16 billion, $18 billion, and you have $18 billion of organic CapEx.

Matt Lofting: Super. Thank you, Patrick.

Operator: The next question is from Irene Himona from Bernstein. Please go ahead.

Irene Himona: Thank you very much. Good morning. My first question on refining, obviously, a very weak quarter. Patrick, you have said before that you are not positive on the business. But do you see grounds for optimism that as with class starts returning 2.2 million barrels a day to the market margins could strengthen meaningfully from the current $25, which I believe is your breakeven 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 TTF next year, please? Thank you.

Patrick Pouyanné: Okay. I don’t know what is – in the first refining. 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 is $35 per ton, which is higher than the $25 today. And that’s why we are working hard to have this breakeven going down to $25 per ton. But I’m moderately optimistic about this event. I think we benefited from two years where during COVID 2021, there was a huge acceleration of some shutdowns of refinery in the Atlantic basins. On both sides, by the way, in particular, on the Americas side in Caribbean Islands in the U.S., a lot of conversion to buy a refinery. Then we 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, EMEA and Europe. We’ve even seen some few small refineries, which were supposed to be a shutdown, which was maintained. And then on the top of it, you had some new refineries, which have started, in particular, in China, which have added an additional capacity – the Chinese were suppose in their policy to shut down some what they call the depots, the old small refineries, but the depots 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 Russian products go to South America, U.S. coming to Europe.

So – and Europe, last point, 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 assisted cycle where I – we stopped, I mean we not TotalEnergies, 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 its job, I would say. One way as you know is to transform these biorefineries – refineries in biorefineries because at the same time in Europe, we benefit from a bit from regulations which push biofuels for having a better demand for biofuels for regulation.

So I would say that’s from the optimism. I’m moderately optimist. I will 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, the $35 per tonne 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, it’s difficult to be there to guess about it. LNG, I don’t know who has said two years. No, I think we were very clear. I was very clear in New York CNG. I told you that we were thinking that the wave will begin not 2026 but 2027. I think nobody never spoke about 2025 having. We don’t see a bigger additional supply in 2025. It was never mentioned. There was a debate between 2026 and 2027.

We are just reading the news, and we have some projects in the U.S., 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 2026, but 2027, 2028, 2029. 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 around $12 per MMBtu. Because again we don’t see in 2025 any additional capacity, which would suddenly change the fundamentals of I would say a market which still under tension.

And then we’ll see by 2026 and of course, we will follow carefully all the news of startup of delays along the year 2025. So again, I’m not sure to one year 2027 yes, two years no, and 2025 should remain in our view, so same type of environment that we have benefited in 2024. So positive for TotalEnergies as a big LNG player.

Operator: The next question is from Christopher Kuplent from Bank of America. Please go ahead.

Christopher Kuplent: Thank you very much. Good afternoon. Just two questions on renewable, 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.

Patrick Pouyanné: The first one is quite easy. We had an option which was negotiated with RWE because as you’ve noticed, we made a farming in the Dutch offshore wind in connection with our well to decarbonize our Zeeland Refinery through green hydrogen. So that was part we negotiated an option. RWE was efficient, I would say, and successful to get access two offshore wind licenses with a low cost of entry. So it would be strange for us not to exercise our option because obviously, so 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 RWE is also a good option for us and for them to grow 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 contemplate. And for us, I would say we have more options offshore wind Germany and so we will see in which order we must develop the different package. But again, it’s a – it was a good opportunity and the answer from this perspective was obvious to us. And the – I don’t like to comment the move of my competitors. I respect each. Everybody has its own strategy. Our Norwegian, France are very focused on offshore winds. So they are probably good answers. What is clear is that in my view, just to comment, I know we have been consistent to become a minority shareholder of a competitor without on our side an industrial strategy.

We never done it. And so when we went to Adani, yes, we are minority shareholders at Adani Green, but we developed at the same site 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 Equinor, but I think I respect that 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 that decision.

Christopher Kuplent: Understood. Thank you.

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

Martijn Rats: Hey, I wanted to get back to the question that Irene also asked about, which is refining margins specifically in Europe, because there are 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, seemingly not in the Total portfolio. So I just want 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 call, 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 after now and how do you expect that to develop over the next one or two quarters, please. Thank you.

Patrick Pouyanné: Okay. On refining margin, honestly, I’m not sure we are big enough to consider ourselves running cutting grants just to please our competitors. It’s this type of strategy, which is – which there is not an OPEC of European refiners. So I mean we are today at the breakeven 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 variable costs? Breakeven 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. We are largely covering our variable costs.

So that’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 in biorefineries in 15, in 20, as we have been always clear and we are working on the follow-up of this one 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 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 variable costs, obviously you have to run in order to cover part of a fixed cost. Second question, I mean, let me clear, we are – I don’t know, 7%, 8% was last year, we have more – that we have explained to you, there is in the 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 reason. For this quarter, as you see, we still have and I think Jean-Pierre was clear in his speech, we anticipate a working capital release of $2 billion for the next quarter. So which is in line with what was the guidance we gave since the beginning of the year we had a big cash, I mean, working capital 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 on 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 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 of again phasing the divestments. And 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. Last minute that come, the last quarter, and we don’t push them necessarily just to finalize all these close the deals before 30 of September, 31 of December. But it’s not only Total Energies, it’s a common practice. So I would say, my view is that we should get come back to something like around 11%, 12% by the end of the year.

This is what we can anticipate on – if of course, we remain in these type of environment, price environment of today. That’s what I can tell you. But again, I know you, Martin, this type of gearing was anticipated 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 buyback of 2023, which means at least by 3% to 5%, it was anticipated this type of gearing level.

Martijn Rats: Wonderful, thank you.

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

Doug Leggate: 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 appears 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 breakeven is $25, but are there any assets you would consider rationalizing at this point if this continues?

Patrick Pouyanné: Again, we’ve done it and we’ve done it with Le Mans 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 – but turnaround of refineries, it happens every four or five years or some of them, by the way, in our case are making turnarounds every two years. Some of them have more longer cycles, four, 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 with the way we have selected Le Mans that we are selecting 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 – we have six, seven refineries I think today still remaining in one, two, three, four, five, six refineries in Europe. We know each of these assets, we know their strengths, we show their weakness 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 as each of these events is 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 have spent the money on the platform to just after announce that we will shut down.

But again, that’s – for me, it’s not because this strategic thinking is not linked to the low cycle of today. We are prepared. Since we have launched 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, including this biofuel market in Europe is moving today. It’s facing some oversupply. So this type of thinking could affect us in North Canada, but so we will – 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, the 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 shut down before us normally the way it works, otherwise. So we’ll see. And having said that, again, our ambition, I would say, more on the opportunistic – on the opportunity side, the positive side, that we consider that this biofuel market, the staff market in Europe with a mandate of 6% is giving good opportunities for brownfield projects rather than for greenfield ones. So we exclude greenfield, so we’ll and we have the ambition to continue to benefit from this market.

Doug Leggate: Thank you for the full answer, Patrick. My follow-up is a quick one on Suriname. Obviously, you – suddenly 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 tieback 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.

Patrick Pouyanné: We are the operator of the project.

Doug Leggate: So what’s your view on the long-term plateau?

Patrick Pouyanné: 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 high plateau level because we consider that GranMorgu 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.

Doug Leggate: Terrific. Thanks so much.

Operator: The next question is from [indiscernible] from Bank of America. Please go ahead.

Unidentified Analyst: Hi. Thanks for taking my question. I just had one related to back to the CFFO, again, at the start of this year, you gave CFFO guidance, which looks like it’s something close to $34 billion [ph]. 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.

Patrick Pouyanné: I don’t remember $34 billion, I had $32 billion 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 are very completely replenished. It has a seasonal effect. We are back since this summer to $12 per million BTU, $13 per million BTU, more in line with our assumptions. So I would say there is $1 billion somewhere for me, which – which is linked to this gas. The market has been less volatile, and it’s true that in a less volatile market or trading business has been a performance, which was very good, more than super good with excellence in 2022, 2023, benefiting from big volatility when the market is quite stable, it’s more difficult.

So I would say there is $1 billion [indiscernible] 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. We think we’re losing, I would say, I don’t know, I don’t have the figures in my $500 million more or less. We – I think the best – 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, the main elements I have in mind. But what I suggest, Biraj, is that, again, I’m trying – my teams try to calculate quicker than me. So 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 billion and the $30 billion.

Okay.

Unidentified Analyst: Okay, that’s fine, thank you.

Patrick Pouyanné: So gas and refining.

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

Lucas Herrmann: Yes, thanks very much. A couple as well, if I might. I wanted 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 Chappal is that expected to complete – where are things with the authorities just a – and also could you make any comment on Nigeria 7 and progress in terms of development and timing – and just generally on gas close into Nigeria LNG and how those have been progressing through this year and may have a play to your off-take. And then secondly, just if JP perhaps could comment at all on the write-off that you’ve taken this quarter of $1 billion or so of asset write-down, which looks very much as though with SunPower, but just explain to me – that’s it. Thank you very much.

Patrick Pouyanné: Okay. On the onshore assets [ph] well I think we have progressed. There are some have we received some approval from MPC. I think recently, the regulator said that we should have a green light. So we are working on it. And just we are not in the same position that some of our peers because we are not operating and we are in non-operating position. So I think it’s easier for the authorities to evaluate the quality of the buyer because we are a 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 improve. And we have the – our buyer, by the way, have been already approved recently in a deal on an offshore asset, and non-operated offshore asset.

So it’s – it’s a buyer with well-known biofuel authorities. So I do not anticipate difficulties on it. And we have – so we receive there is a process to follow. – and we are following that carefully. So that’s point. On Train 7, as you know, we have been working hard for the last year, in order to obtain the good right terms to be able to develop some new gas projects in order to fill the Train 7 because it’s – as you know, we have already some difficulty to supply all the gas through 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, but it’s time to accelerate the sanctioning of gas projects in order to fill this range. We have got some improvements, in particular on the transfer gas price between the upstream and the downstream.

Ourselves, we have sanctioned the first projects, Ubeta, which has been sanctioned this year, which is dedicated to fill this Train 7. So TotalEnergies will be in line with its commitments in terms of supplying the first the seven trains. We are working on another one, which is called IMA, which is a small – very quite low-cost gas fell very next to Bonny Island. 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 [indiscernible] fiscal leaves 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 would say I’m positive on that.

The write-off, I think Jean-Pierre is clear, there are two parts. One was linked to SunPower company went to Chapter 11, so we had to write-off what was remaining because capital employed. And another part was linked to the decision that South African assets, where we made some discoveries, but the monetization of these gas discoveries was too difficult. In fact, there is no gas markets in gas infrastructure are very limited. The possibility to go from gas to power is also very complex, because you can really newspaper the situation of Eskom 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 the development or we were stopping losing the assets. So I would say that was also a question of time line, which led us to take that decision.

And it’s true, but – by the way, just to remind you, a long story on the South Africa, when we took these licenses was not to discover gas. That 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 all is easier to monetize in the – in South Africa and gas. So in particular, when gas is not located next to customers and most of the industries in South Africa are not on the cost line for the country, but they are more in the northwest of the country, so a little far away. So it has never been easy. It’s the gas market there, and that’s the conclusion. So – but the two reasons why we make these to write-off this quarter.

Lucas Herrmann: Can I just push you a bit more on Nigeria, if I think about startup of Train 7. What’s your latest commentary on when you might expect that to happen? And secondly, I mean, gas prices used to be nominal. So on very low till low in Nigeria. Just some sense of what you’re actually able to – or what price – so I say what price do you need in order to justify an adequate return on the investment you’re making?

Patrick Pouyanné: So Train 7 is expected to start up by 2026, probably end of 2026. That’s part of the ones which are not to come back to a question that I had before, that’s one of the train, which probably will not be in advance, to be clear.

Lucas Herrmann: Okay.

Patrick Pouyanné: Okay? So you can push it more to 2026 to 2027 or other than 2026, 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 say, spend the CapEx according to also the feed gas. Okay?

Lucas Herrmann: Yes. And price on gas that you’re managing to get from the Nigerian to agree or NLNG to agree?

Patrick Pouyanné: No, it’s done. We have an agreement with them. We have increased and all the partners of NLNG, I have agreed, but the gas transfer price from the uptrend to the plant will be higher which is no more 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 have 60% in NPC. And then you have the three major players, Shell, TotalEnergies and Eni, which were on both sides. So in fact, the transfer price was an issue for the only JV, which was not participating to NLNG, which was, in fact, by that time, the Conoco JV. 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 have 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 TotalEnergies should develop more gas than its share for the benefit of other partners in NLNG. That was not very fair. So that was the discussions, and we solve it collectively in the interest to drop more gas upstream. And of course, that means that the 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.

Lucas Herrmann: Great. Patrick, thank you. JP, thank you.

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

Kim Fustier: Hi, thanks for taking my questions. I’ve got two, please. First on the outage at Ichthys LNG, you’ve talked to 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 Ichthys 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 few quarters. Could you talk about how your cost of debt is evolving as you refinance debt at presumably higher interest rates? Thank you.

Patrick Pouyanné: Kim, I’m sorry, but I’m not in charge of all the exchanges of the company. And by the way, we are not operating Ichthys. So something happened there. It has been solved. That’s the point. And I think by the people in charge of operations are driving the lessons about 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 this type of unplanned events. That’s life, I would say. Financial impact on Q4, I think it has been solved. I think now as I think Ichthys as we started, if I come into my information, so it should be – the impact should be – it’s not only $200 million. I don’t know why you mentioned $200 million or $300 million. I’m not sure it was so big as an individual because there were different impacts on the cash. It’s not only Ichthys, this is part of it. I don’t know you have an idea, Jean-Pierre.

Jean-Pierre Sbraire: No, I don’t have any idea.

Patrick Pouyanné: Debt and interest rates, I will let Jean-Pierre is the expert of this debt management.

Jean-Pierre Sbraire: Yes, 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 oversupplied and with very long maturities. So it’s the strategy, we continue to implement is to try to have longer maturity 30, 40 years as that rectified. But once again, at present time it’s very competitive bond portfolio.

Patrick Pouyanné: Okay. Just before we take the 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 billion was expecting. We are more today at $30 billion, $31 billion 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. the last $500 million, I’m not sure to have the figures. But just I’m correcting, I can easily go from $34 billion to $31 billion, let’s say, and then there is something which are different elements, but we’ll come back to you next February involves the details just to be sure that the elements are shared with everybody.

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

Henri Patricot: Thank you for the update. Two questions, please. The first one, actually, just a quick follow-up on the comments around the CFFO generation in the year. I was wondering if in 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 store ramp-up of best or underlying performance elsewhere in the business? And then secondly, on the Integrated Power ROACE dipped below 10% this quarter. How quickly should we expect that ROACE to go back above the 10% level?

Patrick Pouyanné: Okay. Second one is quite easy. It’s linked to the calendar of the farm downs. In fact, as I told you before, we have – it’s the farm downs when you make it on the renewables have quite an impact because, of course, not only you – in terms of capital employed, it has – you will not only eliminate the share of the 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 is more on the capital employed linked to the agenda of the farm downs.

On the chemicals, I would say the chemicals, you follow probably some chemical companies. We are only on 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 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 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 Chinese have been very active in fact to again be more self sufficient.

And so of course this is a point, so for me margins are correct globally but not very high. And so we are not in the high cycle, we are 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 new chemicals is more. We are more downstream and you have more of the 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.

Henri Patricot: Thank you.

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

Paul Cheng: Thank you. Good afternoon or good morning. Patrick, just curious that for the integrate 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.

Patrick Pouyanné: Yes. And you forget and the customer portfolio because there are three segments of revenues or contribution. One is renewable parts, 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-third 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, the CFFO is great today.

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

Patrick Pouyanné: Well, LNG, we have been very transparent and the market we said that we interrupted the whole tender process because the CapEx was too high. We stopped and we have together with our partners we have taken some review. We have reviewed some I would say of the basis of design in order to streamline the projects. And we have also been to a larger pool of contractors, in particular some Asian contractors and according to my information we have the retendering has begun. That means we have launched now the process to all these 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 load cheap – to make cheaper costs, cheaper concepts.

And we expect all that will 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 reengaged. 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 either in India or in China we can find some contractors. We had an appetite in which we are quite good to and quite happy to be invited to contribute and we have of course made all the qualification processes and the teams are working very closely with them in order to have some good and competitive offers. So it’s on its way.

Paul Cheng: And Patrick, go according to plan when is the first guess is going to be?

Patrick Pouyanné: I think it was written in our CMD booklet so I don’t have that in mind. It’s 2028. No, I’m not sure. It was written in the slide on the booklet. So I don’t know everything by far. Maybe my team can help me on this one. I will try to find it, one minute; 2028.

Paul Cheng: Okay, thank you.

Patrick Pouyanné: 2028.

Operator: The next question is from Henry Tarr from Berenberg. Please go ahead.

Henry Tarr: 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 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.

Patrick Pouyanné: I mean 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 a lower margins? It’s because two countries in the north of Europe, Sweden and Finland which we are planning to have a mandate for biodiesel, which was above the minimum of Europe. So it was announced. It was planned quite sublet it was 30% instead of 10%. So some competitors have built some plants and for making – producing HVO renewable diesel. And unfortunately, new government came in and they modified the mandate to come back to the, I would say, standard by European mandate around 10%.

So that created an oversupply, and then the HVO margins have decreased. So that’s the difficulty in that felt – that’s why when I was ensuring, of course, we are following that carefully because – it’s not – it’s a niche, but the niche could be full quickly. And I love the game of the airline companies who are pushing us up to produce more. In fact, they want us to have another supplier that as the price to go down. You know, it’s quite easy. So we are complaining there is not enough stuff. And today maybe we are intention, 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 have enter into another supply market. So we are evaluating that and we are obliged. Now I think the lesson we drawn is let’s be cautious.

All these guys are announcing higher mandates, voluntary mandates. I’m only trusting the minimum legal standard mandates. This one 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 U.S. in the U.S. it’s not exactly the same market because all the buyers from the U.S. cannot move to Europe because I would say the content and the regulations, so that what we call the biofuel in south in Europe, but in the U.S. is not exactly the same. So that’s more protection from its perspective.

But that’s part of the work on which we need to be serious before too. There is also, as we told you in New York and other things to take into consideration is that there is some new aviation regulation which allowed to you make some coprocessing in some existing refineries. So obviously we have to evaluate. It’s an opportunity for us first for our refinery to have better, to drive better value for more existing assets. But we need to evaluate properly how much of this coprocessing could be used by the global industry in Europe because it will be a competitor to any greenfield or brownfield project. So we need. That’s also part of the equation that we have to take into account.

Henry Tarr: That’s great. Thanks for your answer.

Operator: The last question will be from Jason Gabelman from TD Cowen. Please go ahead.

Jason Gabelman: Yes. Hey, it’s Jason Gabelman from TD Cowen. 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.

Patrick Pouyanné: I mean, first, I hope you are right in your assumption. The war [ph] 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 move in the continent, if there was this [indiscernible] if war was ending. So no bull on it now. No, it’s quite easy. The dividends of Novatek were representing around $600 million per year. So they are stucked, most of them are stuck in on the Novatek accounts, not on the Sea [ph] accounts, because we are Novatek has kept this 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 under the 500. So I don’t know when it will end. So probably by the end of the year will be $1.5 billion 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. What’s the point?

Jason Gabelman: Yep, that’s helpful. Thanks. And then just going back or turning to CapEx and 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, SapuraOMV that hasn’t closed yet. So just wondering as we are 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.

Patrick Pouyanné: No, we will not breach. Okay, we told you, we confirmed $17 billion, $18 billion, so we confirm it. In fact, just to transparent with you, the organic CapEx by the end of September were around $12.5 billion. So if I’m adding another three to four, you will go to $16.5. There might be more M&A and more acquisition 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 confirm the guidance of $17, $18. So you make the difference between $17, $18 and $14. It makes $3 billion to $ 4 billion 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 OMV acquisition in Malaysia.

We’ll see. 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 will be probably $16 around $16. Okay?

Jason Gabelman: Great, thanks.

Patrick Pouyanné: Good.

Operator: Gentlemen, do you have any closing comments?

Patrick Pouyanné: Yes, we’ll have some comments. So thank you for your attendance. Okay. Again, I think the quarter, of course is lower than the previous ones. It’s clear because we have been, I would say it is as 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 return to shareholders and a strong return to shareholders guidance. Keep in mind that the year 2025 will also be positive. We told you in New York that will 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.

Mero-3 started up, so the ramp up will begin. We had Mero-2 which is going to its maximum. And so I can confirm to you that 2025 will have a production more than growth by 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.

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