TotalEnergies - Q3 2024
October 31, 2024
Transcript
Operator (participant)
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 (CEO)
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 this month. Just spent the last three weeks in roadshows, and I would like just to share with you that we got 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 break-even portfolio, and a strong balance sheet supporting attractive shareholder returns are our 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 any longer, and I will hand over to Jean-Pierre to discuss the details of the third 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 your questions during the Q&A.
Jean-Pierre Sbraire (CFO)
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 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 million-2.45 million barrels of oil equivalent per day. We continue to see good performance from project ramp-ups, mainly Mero 2 in Brazil, which partially offsets unplanned shutdowns in Ichthys LNG, and security-related disruption in Libya. In addition, during the third quarter, we achieved first oil at the high-margin Anchor project in the Gulf of Mexico in the U.S., and first gas at the Fenix field offshore in Argentina.
We expect production for the fourth quarter 2024 to be between 2.4 million-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 2 project in Brazil that compensates for several planned 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 project, a large 220,000 barrels per day FPSO located offshore Suriname, with estimated recoverable oil reserves of more than 750 million barrels. These low-cost, low-emission developments were sanctioned one year only after the end of appraisal and are designed to accommodate future tying opportunities to extend the production plateau. GranMorgu is the company's sixth major oil and gas FID of 2024, all of which de-risk their medium-term production growth objective of 3% per year through 2030, which ultimately translates into growing shareholder distributions.
Exploration and Production ASC 932 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 Energy. 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. 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 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 tons. In addition, we enhance 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. On the 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 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, for 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 a strategic CCGT acquisition located in the deregulated U.K. 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 wind. In the upstream, 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 rest of the world. In Refining and Chemicals, the company's European refining margins fell to $15 per ton in Q3 due to normalization of trade flows after the Russian ban and import supply related to recent capacity increase. 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 2024, the company anticipates refining utilization rate will remain above 85%, with a turnaround planned at Leuna Refinery in October. Marketing and services result remains 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 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 5/6/7 in South Africa. After the build reported in the first quarter, a first working capital release was reported during the second quarter, and a new release of $0.4 billion was reported this quarter. 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 remained robust with return on average capital employed at 14.6%. Capital discipline is strong. We confirmed 2024 net investment guidance of $16 billion-$18 billion. Lastly, we continue our track record of strong shareholder distribution. Buyback is 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-year dividends up nearly 7% compared to 2023 and up 20% compared to pre-COVID levels. We'll stop here, and with that, Patrick and I are available to answer your questions.
Operator (participant)
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 one on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking a question. If you wish to cancel your request, please press star two. Once again, please press star one if you wish to ask a question. The first question is from Lydia Rainforth from Barclays. Please go ahead.
Lydia Rainforth (Managing Director)
Thank you, and good afternoon, and thank you for the presentation. Two questions, if I could answer. 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 a normal 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 (CEO)
On the cash flow, I think Jean-Pierre mentioned in his pitch that there was a, we had a, what would they?
Jean-Pierre Sbraire (CFO)
A lag effect.
Patrick Pouyanné (CEO)
A lag effect on some SMEs between the results and the cash dividends.
Jean-Pierre Sbraire (CFO)
Yes.
Patrick Pouyanné (CEO)
Mainly LNG SMEs, so it's why it's affecting the Integrated Energy 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, so that's, I would say, 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 acreage in Argentina. We know that we manage that quite cautiously. We just recirculate the 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 particularly, there is 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 Argentine president when I met him last month, we want our money back, you know. 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.
We will, of course, analyze the different options we have in that view.
Operator (participant)
The next question is from Michele Della Vigna from Goldman Sachs. Please go ahead.
Michele Della Vigna (Managing Director)
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.
Patrick Pouyanné (CEO)
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 globally, I mean, positive. In fact, 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—I mean, again, as you know, there are different aspects in Mozambique. One of them was the 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 stability in the country will come, the better it is for all of us. Having said that, we are more focused on our side on Cabo Delgado. And on Cabo Delgado, the 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, is 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 different on the financing of the project. As 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 force majeure. All the export credit agencies have done the due diligence 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 export 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 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 oil companies the same type of reporting framework as the one we have, and it's a way to progress, to share also a lot of experience and sort 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—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 factors on which we'd like to see progress is on the question of the carbon credits, if any more Article 6, how can we—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 in the stronger investments in that field. So that's, I would say, the main expectations on our side.
Michele Della Vigna (Managing Director)
Thank you.
Operator (participant)
The next question is from Matt Lofting from JPMorgan. Please go ahead.
Matt Lofting (Energy Equity Research Analyst and Executive Director)
Hi, James. 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 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 the beginning of October with 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 look to activate some or all of the $2 billion CapEx flex that you talked about? Thank you.
Patrick Pouyanné (CEO)
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 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, 32. We were higher expectations on one side with 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 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 CapEx? No, the CapEx for me at $2 billion, it's not at $70, but we'll change our strategy, our policy. From this perspective, $70. When we speak about short-cycle CapEx, we start 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 that 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 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 CMD, you can consider them good.
By the way, I remind you, just to correct slightly, Jean-Pierre, it's 17-18, not 16-18 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 the $18 billion of organic CapEx.
Matt Lofting (Energy Equity Research Analyst and Executive Director)
Super. Thank you, Patrick.
Operator (participant)
The next question is from Irene Himona from Bernstein. Please go ahead.
Irene Himona (Managing Director)
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+ starts returning 2.2 million barrels 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 TTF next year, please? Thank you.
Patrick Pouyanné (CEO)
Okay. I don't know what it is, and first, refining. Refining, the average margin, on you can take different metrics, is around $35 per ton in 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 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, 2021, there was a huge acceleration on some shutdowns of refinery in the Atlantic Basin, on both sides, by the way. In particular, on the America 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 ocean 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 even seen some few small refineries which were supposed to be shut down, which were 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 supposed in their policy to shut down some what they call the teapots, the old small refineries, but the teapots are still cooking, I would say. And that means that you have quite a lot of supply at the same time.
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. Europe, last but not least, as you know, the industry demand in Europe is not very strong today. That means that we are back, I would say, to the traditional cycle where we stopped, I mean, not TotalEnergies, but the industry stopped, I would say, restructuring to capture the good margins. 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's from the optimism. I'm moderately optimistic. I will be more optimistic if I see more, I would say, announcements about shutting down refineries, but it takes time. It takes time. So let's see. The $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, 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 CMD.
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 big additional supply in 2025. It was never mentioned. There was a debate between 2026 and 2027. We are just reading the news, and you have some projects in the U.S. which have been delayed for different reasons. So I would say, in 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 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 $12.40. TTF must be more or less at the same level as NBP. We anticipate for 2025 something in the same range. I think I would say around an average around $12 per million BTU 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 tension. Then we'll see by 2026. Of course we will follow carefully all the news of startups or delays along the year 2025. Again I'm not sure. To one year, 2027, yes. Two years, no. 2025 should remain, in our view, the same type of environment that we have benefited in 2024. It is positive for TotalEnergies as a big LNG player.
Operator (participant)
The next question is from Christopher Kuplent from Bank of America. Please go ahead.
Christopher Kuplent (Director of Research)
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 Ørsted and whether you would contemplate anything similar for Total. Thank you.
Patrick Pouyanné (CEO)
The first one is quite easy. We had an option which was negotiated with RWE because, as you've noticed, we made a farm in their Dutch offshore wind in connection with our will to decarbonize our Zeeland refinery for green hydrogen. So that was part. We negotiated an option. RWE was efficient, I would say, and successful to get access to two offshore wind licenses with a low cost of entry. So it would be strange from us not to exercise our option because, obviously, so they worked well. We benefited from it, and it's good for us. That could let us, of course, to, 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 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 template. 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 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, they are very focused on offshore wind, so they have probably good answers. What is clear is that, in my view, just to comment, 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 with Adani, yes, we are a minority shareholder of Adani Green, but we developed on the same site some GW 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 Ørsted and Equinor, 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 I would not have considered such acquisition, but again, I respect their decision.
Christopher Kuplent (Director of Research)
Understood. Thank you.
Operator (participant)
The next question is from Martijn Rats from Morgan Stanley. Please go ahead.
Martijn Rats (Managing Director and Equity Research Analyst)
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, 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 call, you talked about the sort of underlying level of about 7%-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, the 12 that we're now at, and how do you expect that to develop over the next one or two quarters, please? Thank you.
Patrick Pouyanné (CEO)
Okay. On refining margins, honestly, I'm not sure we are big enough to consider ourselves running cutting runs just to please our competitors. That's the type of strategy which is, there is not an OPEC of European refiners. So I mean, we are today at the break-even, and I think it's something which, because then 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. Break-even is calculated in terms of fixed plus variable costs. As long as 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 a simple economic theory. So 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 variable costs, obviously, you have to run in order to cover part of the fixed costs. Second question. No, I mean, let me be clear. I don't know if the 7%-8% was last year. You know that we have explained to you. In the gearing, you have different aspects. It's a little high today.
I think we should be back in the range that you mentioned, 10%-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 pitch, we anticipate a working cap release of EUR 2 billion for the next quarter, 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 cap, not really the cash out at the beginning of the year, more than EUR 4 billion, if I remember. EUR 2 billion were perfectly linked to exceptional events of last year, of taxation events on 2023.
And over EUR 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 of, again, of 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.com, 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 TotalEnergies, 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 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 by the buyback of 2023, which is at least by 5%. It was anticipated this type of gearing level.
Martijn Rats (Managing Director and Equity Research Analyst)
Wonderful. Thank you.
Operator (participant)
The next question is from Doug Legate from Wolfe Research. Please go ahead.
Doug Legate (Managing Director and Senior Research Analyst)
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, I 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?
Patrick Pouyanné (CEO)
Again, we've done it, and we've done it with La Mède in 2015. We've done it with Grandpuits in 2020. And it's quite clear that when we do it, we try to look to the agenda of the shutdowns to avoid spending a lot of money on the refinery and to shut down one year after. So that's part of the budget, you know, shutdown turnaround of refineries. It happens every four, five years. Some of them, by the way, in our case, are making turnarounds every two years. Some of them have much longer cycles, four, five years. So that is taken into consideration. But it's not because of a 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 La Mède or we are selecting Grandpuits is more, in fact, the structural, I would say, weakness or interest to transform them because of their location, because of their markets, etc. 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 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 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 phase 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 plan, 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.
This type of thinking could affect us in Normandy. 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 break-even, I would say. So as we have good assets with low break-even, I'm expecting others to move to shut down before us. Normally, it's 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 soft market in Europe with a mandate of 6%, is giving good opportunities for brownfield projects rather than for greenfield ones.
We exclude greenfield, and we have the ambition to continue to benefit from this market.
Doug Legate (Managing Director and Senior Research Analyst)
Thank you for the full answer, Patrick. My follow-up is a quick one on Suriname. Obviously, 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 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 (CEO)
We are the operator of the project.
Doug Legate (Managing Director and Senior Research Analyst)
What's your view on the long-term plateau?
Patrick Pouyanné (CEO)
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 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 Legate (Managing Director and Senior Research Analyst)
Terrific. Thanks so much.
Operator (participant)
The next question is from Biraj Borkhataria from RBC Capital Markets. Please go ahead.
Biraj Borkhataria (Global Head Energy Transition Research)
Hi. Thanks for taking my question. I just had one related to going 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, 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 billion-ish 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 (CEO)
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 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, with excellent in 2022, 2023, benefiting from big volatility. When the market is quite stable, it's more difficult.
I would say there is one billion probably out of this one, $1.5 billion out of this gas trading and low gas pricing. The other part will come from this refining business, where I think we're losing, I would say, I don't know, I don't have the figures in mind, $500 million, more 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 teams try to calculate quicker than me, 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.
Biraj Borkhataria (Global Head Energy Transition Research)
Okay. That's fine. Thank you.
Patrick Pouyanné (CEO)
So gas and refining. Okay.
Operator (participant)
The next question is from Lucas Herrmann of BNP. Please go ahead.
Lucas Herrmann (Managing Director)
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 Chappal Energies? Is that expected to complete? Where are things with the authorities? Just a 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 may have played to your uptake? And then secondly, just if JP perhaps could comment at all on the write-offs that you've taken this quarter of $1 billion or so of asset write-down, which looks very much as though it's dealing with SunPower. But just explain to me.
That's it. Thank you very much.
Patrick Pouyanné (CEO)
Okay. On the onshore asset sale, I think we have progressed. We have received some approval from NNPC. 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. 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 approve, and we have the buyer, by the way, have been already approved recently in a deal on an offshore asset, a non-operated offshore asset.
So it's a buyer who is well known by the authorities. So I do not anticipate difficulties on it. And we have, so we receive a very strict process to follow, and we are following that carefully. So that's one point. On Train 7, 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 my colleagues as well, or 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. Ourselves, we have sanctioned the first project, 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 seven trains. We are working on another one, which is called Ima, which is a small, very quite low-cost gas field, 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 valorize fiscally 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 would say I'm positive on that. The write-off, I think Jean-Pierre has been clear. 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 of 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 at 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 using the assets.
I would say that was also a question of timeline, which led us to take bad decisions, and it's true that, 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 write-offs this quarter.
Lucas Herrmann (Managing Director)
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, 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?
Patrick Pouyanné (CEO)
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 trains which probably will not be in advance, to be clear.
Lucas Herrmann (Managing Director)
Okay.
Patrick Pouyanné (CEO)
Okay? So you can push it more to 2026 to 2027 rather 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 fuel gas. Okay?
Lucas Herrmann (Managing Director)
Yeah. And price on gas that you're managing to get from the Nigerians to agree or NLNG to agree?
Patrick Pouyanné (CEO)
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 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, 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 in NLNG, which was in fact by that time the Conoco JV. But along the years, as you noticed, and that was why it was so 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 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.
Lucas Herrmann (Managing Director)
Super. Patrick, thank you. JP, thank you.
Operator (participant)
The next question is from Kim Fustier from HSBC. Please go ahead.
Kim Fustier (Senior Global Oil & Gas Analyst)
Hi. Thank you for taking my questions. I've got two, please. First, on the outage at Ichthys 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 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 (CEO)
Kim, I'm sorry, but I'm not in charge of all the heat exchangers 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 my people in charge of operations are drawing the lessons that to avoid these types of issues. It's big machines. 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 types of unplanned events. That's life, I would say. Financial impact on Q4, I think it has been solved, I think now. I think Ichthys has restarted, according to my information. So it should be 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 Ichthys. Ichthys is part of it. I don't have the FID. You have an FID, Jean-Pierre, on the? No, I don't have the FID. Debt and interest rates. I will let Jean-Pierre, he's the expert of all this debt management.
Jean-Pierre Sbraire (CFO)
So it's clear. At the time, I had 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 issuances in the U.S. market, one in April and one in September, very successful because it was largely oversubscribed and with very long 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.
Patrick Pouyanné (CEO)
Okay. Just before we take this next question, I would like to answer 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 billion-$31 billion expecting by the end of the year. So my doubt on the gas, the fact that the gas price was lower, it's $1 billion. The lower gas, trading gas and LNG gas is $1 billion compared to the year before. So it's $2 billion on the, I would say, gas and LNG as a global. And it's $1 billion on the refining margins. The last $500 million, 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 write 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 fair with everybody. Henri?
Operator (participant)
The next question is from Henri Patricot from UBS. Please go ahead.
Henri Patricot (Executive Director and Equity Research Analyst)
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 slower ramp-up of Baystar 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 (CEO)
Okay. The second one is quite easy. It's linked to the calendar of the farm downs. In fact, as I told you before, 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 non-linear impacts along the year, but we should reach the expectations, so 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 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 in the U.S., in particular, there was a wave of ethane cracker, which was built from 2020 to 2023, and we have 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.
Of course, this is the point. For me, margins are correct globally, but not very high. 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. It's more, I would say, chemicals is more we are more downstream, and you have more of the global economic macro will affect them. You can see the IMF expectations for the year are decreased quarter after quarter. That impacts these types of businesses, I would say, in terms of demand. If demand is lower, of course, the margins are following.
Henri Patricot (Executive Director and Equity Research Analyst)
Thank you.
Operator (participant)
The next question is from Paul Cheng from Scotiabank. Please go ahead.
Paul Cheng (Managing Director)
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 earnings or CFFO between the gas-fired power portfolio and the renewable power portfolio? Thank you.
Patrick Pouyanné (CEO)
Yeah. And you forget the end customer portfolio because there are three segments of revenues or contribution. One is renewable power, the gas plants, 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. 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 played today.
Paul Cheng (Managing Director)
Great. And Patrick, can you give us an update where we are on the Papua New Guinea LNG projects?
Patrick Pouyanné (CEO)
NG, we have been very transparent with the market. We said that we interrupted the whole tender process because the CapEx were too high. We stopped. And together with our partners, we have taken some time to 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, the re-tendering has begun. That means we have 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 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, 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 either in India or in China, we can find some contractors. We had the appetite, which we are quite good to be 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 (Managing Director)
And Patrick, if it goes according to plan, when's the first gas it's going to be?
Patrick Pouyanné (CEO)
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 a slide on the booklet, so I don't know everything by heart. Maybe my team can help me on this one. Well, it's almost yesterday. I will try to find it. One minute. 2028.
Paul Cheng (Managing Director)
Okay. Thank you.
Patrick Pouyanné (CEO)
2028.
Operator (participant)
The next question is from Henry Tarr from Berenberg. Please go ahead.
Henry Tarr (Analyst)
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 (CEO)
I mean, this is exactly why I was answering to one of your colleagues previously, that 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 regulations. 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 quite above. I think it was 30% instead of 10%. So some competitors have built some plants for making HVO, renewable diesel. And unfortunately, new governments came in, and they modified the mandate to come back to be, 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 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. And I love the game of the airline companies who are pushing us up to produce more. In fact, they want us to have an oversupply, an oversupply to go down. It's quite easy. So they are complaining there is not enough stuff. And 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 an oversupply market. So we are evaluating that, and we are obliged now, and things are less than withdrawn. It's less precocious. All these guys are announcing higher mandates, voluntary mandates. I'm only trusting the minimum legal standard 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 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 biofuels from the U.S. cannot move to Europe because, I would say, the content and the regulations about what we call the biofuel in the south in Europe, what is in the U.S. is 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 to move.
There is also, as we told you, in New York, another thing to take into consideration is that there is 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 our first refinery to have better value from our existing assets. But we need to evaluate properly how much of this co-processing could be used by the global industry in Europe because it will be a competitor to any greenfield or brownfield projects, so we need that. That's also part of the equation that we have to take into account.
Henry Tarr (Analyst)
That's great. Thanks for your answer.
Operator (participant)
The last question will be from Jason Gabelman from TD Cowen. Please go ahead.
Jason Gabelman (Managing Director)
Yeah. 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 (CEO)
I mean, first, I hope you are right in your assumption. The war will end not only for TotalEnergies, 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 there are no power on it. Now, it's quite easy. The dividends of Novatek were representing around $600 million per year. So they are stuck. Most of them are stuck on the Novatek accounts, not on the SE accounts, because Novatek 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, nothing, no dividends. That means that you have probably another 500. I don't know when it will end. Probably by the end of the year, it will be $1.5 billion-$2 billion of cash dividends, which are somewhere on other accounts. Just to give you a magnitude of it. Of course, it's not the point.
Jason Gabelman (Managing Director)
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, the OMV, 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 (CEO)
No. We will not breach. Okay? We told you we confirmed $17 billion-$18 billion, so we confirm it. In fact, just to be transparent with you, the organic CapEx by the end of September were around $12.5 billion. So if I'm adding another $3 billion-$4 billion, you will go to $16.5 billion. 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 billion by the end of this September. So that means we confirm the guidance of $17 billion-$18 billion. So you make the difference between $17 billion-$18 billion and $14 billion. It makes $3 billion-$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 these OMV acquisitions in Malaysia. We'll see.
I mean, it's a process which is not fully under control, but this is where we are. So I think $12.5 billion 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 billion. Okay?
Jason Gabelman (Managing Director)
Great. Thanks.
Patrick Pouyanné (CEO)
Good.
Operator (participant)
Jason, do you have any closing comments?
Patrick Pouyanné (CEO)
Yeah, we'll have some comments. So thank you for the attendance. Okay. Again, I think the quarter, of course, is lower than the previous ones. That's clear because we have been, I would say, at this refining margin, but it'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 full 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. Mero 3 has 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, we'll have a production more 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'll have to meet you again in coming weeks.