TotalEnergies SE

PAR:TTE

Earnings Call Analysis

TotalEnergies third quarter insights highlight resilience amid challenges.

In the third quarter, TotalEnergies reported a resilient adjusted net income of $4.1 billion despite challenging conditions, including a 66% decline in European refining margins. Oil and gas production remained stable at 2.41 million barrels of oil equivalent per day, within guidance. The company anticipates production for the fourth quarter to be between 2.4 and 2.45 million barrels. With strong cash flow generation at $4.3 billion and a return on capital employed of 14.6%, TotalEnergies plans a capital expenditure of $17 billion to $18 billion for 2024, alongside a $2 billion shareholder buyback program.

Navigating a Volatile Environment

During the third quarter of 2024, TotalEnergies faced a challenging market characterized by deteriorating refining margins, which decreased by 66% quarter-to-quarter, settling below their breakeven point of $25 per ton. For upstream operations, Brent crude prices fell by 5%, averaging $80 per barrel, while the average LNG price slid by 6%. Despite these pressures, TotalEnergies reported an adjusted net income of $4.1 billion for the quarter, bringing the year-to-date total to $13.9 billion and affirming the company's robust profitability.

Production Highlights and Future Outlook

TotalEnergies' hydrocarbon production reached 2.41 million barrels of oil equivalent per day in Q3, consistent with guidance expectations. Key successes included the ramp-up of the Mero 2 project in Brazil and the initiation of production at the high-margin Anchor project in the Gulf of Mexico. Looking ahead, production guidance for Q4 remains steady between 2.4 and 2.45 million barrels per day, buoyed by reduced security disruptions in Libya and the recent startup of the Mero-3 project.

Strategic Investments and Growth Goals

The company is strategically positioned for future growth with the recent sanctioning of the GranMorgu project in Suriname, expected to yield 220,000 barrels per day with over 750 million barrels of recoverable reserves. This initiative aligns with TotalEnergies' medium-term production growth target of 3% annually through 2030, essential for enhancing shareholder distributions. Operating expenditure per barrel remains competitive at $4.9.

Resilience in Integrated Energy and LNG Performance

In Integrated Energy, LNG production saw a 7% decline due to maintenance issues at Ichthys LNG, while sales improved by 8% during the quarter. However, adjusted net operating income from Integrated LNG was reported at $1.1 billion reflecting these challenges. The anticipated average LNG selling price is expected to rise to $10 per Mbtu for Q4, aligning with market dynamics and ongoing contract signings.

Capital Expenditure and Financial Management

TotalEnergies confirmed its net investment guidance for 2024 at $17 billion to $18 billion, with organic CapEx around $12.5 billion as of September. With expectations of close to $30 billion in cash flow for the fiscal year, driven by return on average capital employed at 14.6%, the company is well-positioned to meet its financial commitments including buybacks and dividends.

Emphasis on Shareholder Returns

TotalEnergies has committed to returning value to shareholders with an ongoing share buyback plan totaling $8 billion for 2024, alongside a nearly 7% increase in the dividend relative to 2023. The company aims to stabilize gearing levels at 10% to 12% by year-end, supported by a working capital release of approximately $2 billion.

Challenges and Uncertainties

Despite positive indicators, the financial outlook includes caveats such as global market volatility impacting refining margins and uncertainties in the LNG space due to fluctuating gas prices and geopolitical tensions. The company maintains that while current margins are low, anticipated structural changes in the industry could provide future upside.

Regional Focus: Opportunities in Argentina and Africa

In Argentina, TotalEnergies is cautiously evaluating expansion opportunities, particularly in the oil sector, provided that capital movement restrictions allow for profit repatriation. Meanwhile, projects in Uganda, including significant investments in pipeline infrastructure, are on schedule for a 2026 startup, while Mozambique's operations remain contingent on improved security and political stability.

Conclusion: A Balanced Approach to Growth

TotalEnergies remains committed to a balanced strategy focused on cost discipline, sustainable growth across its hydrocarbon and renewable energy segments, and robust cash flow management. With dedicated initiatives in both oil production and integrated energy, the company is positioned to navigate current market headwinds while staying aligned with long-term profitability and shareholder value objectives.

Earnings Call Transcript 2024-Q3

[Operator]

Ladies and gentlemen, welcome to the TotalEnergies Third Quarter 2024 Results Conference Call.

I now hand over to Patrick Pouyanne, Chairman and CEO; Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

[Patrick Pouyanné, executive]

Good morning. Good afternoon, everyone. Patrick Pouyanne 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 3 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 costs, keeping a low breakeven portfolio, and a strong balance sheet supporting attractive shareholder returns are our fundamental principles, which allows the company to be resilient through the cycles especially when we are entering into an increasingly volatile uncertain environments 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 3 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, executive]

Thank you, Patrick, and good morning, good afternoon, everyone. This quarter, we faced a more challenging environment with refining margins slightly deteriorated with the European refining margin market 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 in the quarter and of $13.9 billion over the first 9 months of the year. Profitability remained robust. We returned 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 2.45 million barrels of oil equivalent per day. We continue to see good performance from project ramp-ups, mainly Mero 2 in Brazil, which partially offset unplanned shutdowns at 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 and the U.S. and first gas at the Fenix field offshore in Argentina.

We expect production for the fourth quarter of '24 to be between 2.4 and 2.45 million barrels of oil equivalent per day, benefiting from the end of security-related disruption in Libya and yesterday's start-up of the Mero-3 project in Brazil that compensates for several planned shutdown during the fourth quarter '24.

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 1 year only after the end of appraisal and is designed to accommodate future tie-in opportunities to extend the production plateau.

GranMorgu is a company, 6 major oil and gas FID of '24, all of which derisk our medium-term production growth objective of 3% per year through 2030 which ultimately translates into growing shareholder distributions. Exploration & Production, ASC 932 OpEx per barrel equivalent remain best in class at $4.9 per barrel for the first 9 months '24 compared to our objective to be below $5 per barrel.

Moving to Integrated Energy. First, on the results. Hydrocarbon production for LNG decreased 7% quarter-to-quarter, primarily linked to unplanned maintenance at 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 effects 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 Mbtu in the fourth quarter '24, slightly higher than the $9.9 per Mbtu in the third quarter. During the third quarter, TotalEnergies strengthened future cash flows by signing several medium-term sales contracts in Asia, bringing total LNG contracts signed year-to-year to 4 million ton. In addition, we have 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 on returns. We returned 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 start-up of 2 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 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 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 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 of $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 '24, the company anticipates refining utilization rates will remain above 85%. We have a turnaround planned at Leuna refinery in October. Marketing & Services results remain strong for the third quarter with adjusted net operating income was $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 5/6/7 in South Africa.

After the build 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 of '24.

As I was saying in the introduction, profitability remained robust with return on average capital employed at 14.6%. Capital discipline is strong. We confirm '24 net investment guidance of $16 billion to $18 billion (sic) [$17 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 '24. Dividend growth is healthy with the third interim dividend, up nearly 7% compared to '23 and up 20% compared to pre-COVID levels. We stop here and with that, Patrick and I are available to answer your questions.

[Operator]

[Operator Instructions] The first question is from Lydia Rainforth from Barclays.

[Lydia Rainforth, analyst]

Two questions, if I could. 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, a very different topic, but we have started to see some transactions in Vaca Muerta in Argentina. Can you talk through what your plans are for Argentina and what you think the opportunity there might be?

[Patrick Pouyanné, executive]

On the cash flow, I think Jean-Pierre mentioned in his speech that there was -- we had 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 which should be reversed. In fact, there is no fundamental reason to have such a difference. It's just a quarterly effect. So that 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 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. 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 proportions. 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 Argentina 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 a freedom to repatriate dividend. 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 that view.

[Operator]

The next question is from Michele Della Vigna from Goldman Sachs.

[Michele Della Vigna, analyst]

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 start-ups 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.

[Patrick Pouyanné, executive]

Okay. Thank you, Michele. Uganda is progressing as per plan. We intend to start the production by mid-'26. The drilling is positive, I would say. I mean, the news from the reservoir point of view are globally positive. In fact, we have no -- so I would say it's progressing and the pipeline itself is being started to be built and laid. So I would say we are on the way to deliver these important projects, 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 -- there are different aspects in Mozambique. One of them was the security. On the security side, I would say we are -- it has progressed.

Of course, the fact that there will be a stable political power in Mozambique is important for us. So we are following the different news from there, and we intend to visit the country when it will be ready. But I think it's, of course, positive. There is -- 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 site in Cabo Delgado. And Cabo Delgado has 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 those projects. With the contractors, we worked hard. Everybody is there.

But as I told you, I think last time, the last point on which we are working, and I hope we'll have good news is that we are working with the different 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 '21 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 COP29, 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 as the one we have, and it's a way to progress to share also a lot of experience and [ short ] of experience in terms of abating methane emissions, which is one of the objectives. So I think that is positive.

On the COP29, I'm not partly -- I mean, I'm not myself -- we are not, I would say, part of the discussions. If 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 credits, if I 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 community 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.

[Operator]

The next question is from Matt Lofting from JPMorgan.

[Matthew Lofting, analyst]

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 9-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 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 look to activate some or all of the $2 billion CapEx flexibility that you talked about?

[Patrick Pouyanné, executive]

Okay. First, on the cash generation, I would say on the cash flow after 9 months, we are at $23 billion, next to [ '23]. So it means we are today at third, last first 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 on the share buybacks. I would say 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 we will change our strategy. Our policy from this perspective is $70. When we speak about short-term -- short-cycle CapEx, it's 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-$18 billion, not $16-$18 billion for the year. $17-$18 billion for the year '24. And for next year, we told you it will be in the range of $16-$18 billion and you have the $18 billion of organic CapEx.

[Operator]

The next question is from Irene Himona from Bernstein.

[Irene Himona, analyst]

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 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 2 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?

[Patrick Pouyanné, executive]

Okay. I don't know what is -- first refining. Refining the average margin on -- you can take different metrics is around $35 per ton on [ 2013 -- '23 ]. 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. I know but I'm moderately optimistic about the this event. I think we benefited from 2 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 biorefinery. .

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 [indiscernible] Europe. We've even seen some few small refineries, which were supposed to be 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 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. So -- 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 cycle. [indiscernible] 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 his job, I would say. One way, as you know, is to transform these refineries 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 the optimism. I'm moderately optimistic. I will be more optimistic if I see more, I would say, announcement about shutting down refinery, but it takes time, it takes time. So let's see, the $35 per ton for me is 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 guess about it.

LNG. I don't know who I say 2 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 '26, but '27. I think nobody never spoke about '25. I think we don't see a bigger additional supply in '25. It was never mentioned. There was a debate between '26 and '27. 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, 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 3 years will, for us, begin maybe second half '26 but '27, '28, '29.

So for 2025, I would say we are expecting TTF, it's seasonal. So it's the average on the year. The average today on TTF is around, I think, $10, $12. Now today, we are more in $12, $13. I have the NBP of 12.4. So TTF has been more or less at the same level by NBP. So we anticipate for '25 something in the same range. I think, I would say, around an average of around $12 per million Btu, because, again, we don't see in '25, any additional capacity, which would suddenly change the fundamentals of, I would say, a market which is still in the tension.

And then we'll see by '26. And of course, we will follow carefully all the news of start-up of delays along the year 2025. So again, I'm not sure to 1 year, '27, yes; 2 years, no, and '25 should remain, in our view, the same type of environment that we have benefited in '24. So positive for TotalEnergies as a big LNG player.

[Operator]

The next question is from Christopher Kuplent from Bank of America.

[Christopher Kuplent, analyst]

Just two questions on renewables, please, from me. I want to double check, Patrick, if you could give us a little more detail on how you feel the current market sits. I think since we saw you in New York, you've farmed into an RWE project. Is it easier to farm in these days? How much more difficult is it to find partners for farm downs that you're looking for in parallel on other projects?

And maybe related to that, please let us know what you think of making a corporate acquisition as Equinor did becoming a 10% shareholder of Orsted and whether you would contemplate anything similar for Total.

[Patrick Pouyanné, executive]

The first one is quite easy. We had an option which was negotiated by RWE because as you've noticed, we made a farm-in in the Dutch offshore wind in connections with our well 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 2 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 work 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 upfront for us and for them to go globally because we need 2 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 was a good opportunity and the answer from this perspective was obvious to us.

On to be -- I don't like to comment the move of my competitors. I respect everybody has its own strategy. Our Norwegian friends are very focused on offshore wind. So they are probably good answers. What is clear is that, in my view, just to comment, and now we have been consistent to become a minority shareholder of a competitor without on our side an industrial strategy. We've never done it. And so when we went to Adani. Yes, we are a minority shareholder of Adani Green, but we developed the same site, some JV 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 their decision. And again, on our side, we think that we can develop organically some efficient offshore wind assets, and that's why we have done it, why we -- I would not have considered such acquisition, but again, I respect their decision.

[Operator]

The next question is from Martijn Rats from Morgan Stanley.

[Martijn Rats, analyst]

I wanted to get back to the question that Irene also asked about, which is refining margin, specifically in Europe. Because there are -- there's quite a lot of sort 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 sort of 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 [indiscernible]? And how do you expect that to develop over the next 1 or 2 quarters, please?

[Patrick Pouyanné, executive]

Okay. On refining margin, honestly, I'm not sure we are big enough to consider ourselves cutting runs just to please our competitors. That's a type of strategy, which is -- there is not an OPEC of the 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 our variable costs. Breakeven is calculated in terms of fixed plus variable costs as long as we are -- the margin is better than the variable cost, 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 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 that we are working on the follow-up of this one, just on one side to capture the opportunity of the European biofuel market. On the other side, because except the last 2 years, generally, it's economically marginal. So this is more an important question for me. Our instructions to our teams is to make the best use of your assets and as long as you cover your variable costs, obviously, you have to run in order to capture -- cover part of the fixed cost.

Second question. No, I mean, let me clear, we are -- I don't know, the 7%, 8% was last year. We have more -- you know that we have explained to you, there is -- 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% to 12% by the end of the year for different reasons. For this quarter, as you've seen, there is -- we still have -- and I think Jean-Pierre was clear in his speech, we anticipate a working cap release of $2 billion for the next quarter, so -- which is in line with what the guidance we gave since the beginning of the year. We had a big cash -- I mean, working cap -- 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 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 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 [ lastminute.com ], the last quarter. And I don't -- we don't push them necessarily just to finalize all these -- close the deal 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 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 -- price environment of today. That's what I can tell you. But again, I know you, Martijn, 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 '23, which means at least by 5%. It was anticipated this type of gearing level.

[Operator]

The next question is from Doug Leggate from Wolfe Research.

[Doug Leggate, analyst]

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

[Patrick Pouyanné, executive]

Again, we've done it, and we've done it with La Mede 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 to spend a lot of money on the refinery and to shut down 1 year after. So that's part of the -- but shutting turnaround of refineries, it happens every 4, 5 years. Some of them, by the way, in our case, are making turnarounds every 2 years, some of them have more longer cycle, 4, 5 years. So that is taken into consideration. But it's not because of the turnaround, which again we will avoid -- we will make a decision before to spend it for sure.

But I would say, again, more the way we have selected La Mede that we are selecting Grandpuits is more, in fact, the structural, I would say, weakness or interest to transform them because of allocation, because of their markets, et cetera. So when we think to this type of -- we have 6, 7 refineries, I think today is still remaining in 6 refineries in Europe. We know each of these assets. We know their strength. We know 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 at each of this event 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 spend the money on the platform to just after announce that we will shut down. So -- 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 it since we have launched Grandpuits. 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 of the supply. So all these type of thinking could affect us in North Canada. But -- so we will -- we are working on it. And -- 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 is the way it works. Otherwise, so we'll see.

And having said that, again, you know our ambition, I would say, more on the opportunistic -- on the opportunity side, the positive side. You know that we consider that this biofuel market, the soft market in Europe with a mandate of 6% is giving good opportunities for brownfield projects rather than for greenfield ones. So we exclude greenfield. So we will -- and we have the ambition to continue to benefit from this market.

[Doug Leggate, analyst]

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 4-year plateau, but with tieback opportunities. Since then, your partner has been suggesting the plateau could be extended as much as to 8 years. I wonder if I could ask you to offer your perspective on that.

[Patrick Pouyanné, executive]

We are the operator of the project.

[Doug Leggate, analyst]

So what's your view on the long-term plateau?

[Patrick Pouyanné, executive]

I stick to what we told you. We are the operator of the project. We said that this plateau is designed for 4 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.

[Operator]

The next question is from [ Biraj Borkhataria ] from Bank of America.

[Unknown Analyst]

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-ish billion that you maybe originally envisaged and the $30 billion or so that you mentioned today. Any moving parts there would be helpful.

[Patrick Pouyanné, executive]

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 very 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 or trading business has been a performance, which was very good, more than good, super good, was excellence in '22, '23, 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 elements I have in mind. But what I suggest, [ Biraj ] is that, again, I'm trying -- my team is trying 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, gas and refining.

[Operator]

The next question is from Lucas Herrmann of BNP.

[Lucas Herrmann, analyst]

Yes. 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 the commentary. And also could you make any comment on Nigeria 7 and progress in terms of development and timing? And just generally on gas close into Nigeria LNG and how those have been progressing through this year and may have a clear impact on your offtake?

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 associated with SunPower, but just explain to me. That's it.

[Patrick Pouyanné, executive]

Okay. On the onshore asset sale, I think we have progressed. There are some -- we received some approval from NNPC. I think recently, the regulator said that we should have a green light. So we are working on it. 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 approve. And we have the -- our buyer, by the way, have been already approved recently in a deal on an offshore asset, a non-operated offshore asset. So it's -- 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 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 this Train 7 because it's -- as you know, we have already some difficulty to supply all the gas through the first 6 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 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 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 7 trains.

We are working on another one, which is called [ Erema ] 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 '25. So it's a good opportunity to monetize gas reserves. The authorities have enhanced, I would say, the global package to valorize fiscally these 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 said is clear. There are 2 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 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 market. The gas infrastructure is very limited. The possibility to go from gas to power is also very complex because you can read in newspapers the situation of 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. 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. It was because we were 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 cost lines of the country, but they are more in the northwest of the country, so a little far away. So it has never been easy if it's the gas market there, and that's the conclusion. So that's the 2 reasons why we make these 2 write-off this quarter.

[Lucas Herrmann, analyst]

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 -- 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, executive]

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

[Lucas Herrmann, analyst]

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

[Patrick Pouyanné, executive]

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 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% NNPC. And then you have the 3 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. No, that was not very fair. So that was the discussions, and we solve it collectively in the interest to develop 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.

[Operator]

The next question is from Kim Fustier of HSBC.

[Kim Fustier, analyst]

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. So 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?

[Patrick Pouyanné, executive]

Kim, I'm sorry, but I'm not in charge of all the heat 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 people in charge of operations are drawing 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 event. That's life, I would say.

Financial impact on Q4, I think it has been solved. I think Ichthys has restarted according to my information, so it should be -- the impact should be -- it's not only $200 million. I don't know why you mentioned $200 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. Ichthys is part of it. I don't have the idea. Do you have an idea, Jean-Pierre. No, I don't have the idea. Debt and interest rates. I will let Jean-Pierre, he is the expert of this debt management.

[Jean-Pierre Sbraire, executive]

At the present time, I have a very good portfolio in terms of costs below 4% globally. So I do not see the reason why I should reach finance. What we did, we made 2 insurance in the U.S. market, one in April and one in September, very successful because it was largely oversupplied 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 the present time, it's very competitive bond portfolio.

[Patrick Pouyanné, executive]

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, it's $1 billion. The lower gas, trading gas and LNG gas is $1 billion, so compared to the year before. So it's $2 billion on the, I would say, gas and LNG as a rule, and it's $1 billion on the refining margins. So last $500 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 with all the details. So just to be sure that the elements are shared with everybody.

[Operator]

The next question is from Henri Patricot from UBS.

[Henri Patricot, analyst]

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 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 still ramp-up of Baystar underlying performance elsewhere in the business?

And then secondly, on the Integrated Power ROCE dipped below 10% this quarter. How quickly should we expect that ROCE to go back above that 10% level?

[Patrick Pouyanné, executive]

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, 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 will 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 capacity, 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 the ethane cracker, which was built from 2020 to 2023, and we are part of it.

So quite a more supply linked to a low -- cheap ethane cost, which is there. But most of these capacities in the U.S. were, in fact, invested to export. And at the same time, we've seen that the Chinese have been very active, in fact, to, again, be more self-sufficient. And so of course, this is the point. So for me, margins are correct globally, but not very high. And so it's -- we are not in the high cycle. We are, I would say, in the middle, low cycle for chemicals products today. It's less critical than the refining dip. We are making some positive results, but it's not a beautiful market. But it's more -- I would say, 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 expectation for the year 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.

[Operator]

The next question is from Paul Cheng from Scotiabank.

[Paul Cheng, analyst]

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 renewable power portfolio.

[Patrick Pouyanné, executive]

Yes. And you forget and the customer portfolio because there are 3 segments of revenues or contribution. One is a renewable part, 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 3/3 between the 3 parts. 1/3 around renewables, 1/3 about the gas plants and 1/3 by the customers. So just to give you a rule of thumb in the way the CFFO is split today.

[Paul Cheng, analyst]

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

[Patrick Pouyanné, executive]

Well, LNG, we have been very transparent and the market, we said that we interrupted the whole tender process because the CapEx were 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 bid 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 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 low cheap -- to make cheaper thoughts, 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 and which we are quite good to -- 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, analyst]

And Patrick, you go according to plan, when the first gas is going to be?

[Patrick Pouyanné, executive]

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 heart. Maybe my team can help me on this one. I will try to find it, one minute. 2028.

[Operator]

The next question is from Henry Tarr from Berenberg.

[Henry Tarr, analyst]

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 2 to 3 years? Clearly, we're in a little bit of a period of weak margins currently.

[Patrick Pouyanné, executive]

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 2 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 above, I think 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 answering, 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 an oversupply and the price to go down. I know it's quite easy. 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 have enter into an oversupplied 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 about what we call the biofuel [indiscernible] in Europe, but U.S. is not exactly the same. So that's more protection from this prospect. 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 allow to make some coprocessing in some existing refineries. So obviously we have to evaluate. It's an opportunity for us first our refinery to have better -- to drive better value for more existing assets. But we need to evaluate properly how much of this coprocessing would be used by the global industry in Europe because it will be a competitor to any greenfield or brownfield projects. So we need to -- that's also part of the equation that we have to take into account.

[Operator]

The last question will be from Jason Gabelman from TD Cowen.

[Jason Gabelman, analyst]

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, executive]

I mean, first, I hope you are right in your assumption. The war will end not only for TotalEnergies, but more for the piece in our continent. And by the way, I think it will be important for the global economic mood in the continent, if there was this end -- this war was ending. So no [indiscernible] 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 in -- on the Novatek accounts, not on SE accounts because Novatek has kept this dividend on account for us, in fact. So this represents around $1 billion more or less, I would say.

And then you have part of the Yamal dividends as well, which was at the beginning, we managed to get them, and we were transparent. We were, by the way, publishing it. Today, there is no publication because there is little or nothing, no dividends. So that means that you have probably another $500 million. 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 the point.

[Jason Gabelman, analyst]

Yes. That's helpful. 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, executive]

No, we will not breach, okay? We told you we confirm $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 to $4 billion, you will go to $16.5 billion. There might be more M&A, more acquisitions by divestments. 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. 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 to $4 billion of CapEx, which is quite consistent with what we just said and it includes -- to be clear, I included in that the possibility that we close this OMV acquisition in Malaysia. We'll see. I mean it's a process which is not fully under our control, but this is where we are. So I think [ $12.5 billion ] organic, you can calculate, we are not at the high end of this $18 billion we mentioned for next year. We are far from it from this year in terms of organic, will be probably around [ $16 billion ].

[Operator]

Gentlemen, do you have any closing comments?

[Patrick Pouyanné, executive]

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 one. It's clear because we have been, I would say, [indiscernible] 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 globally, and it 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 '25 will also be positive. We told you in New York that we'll enter into a growth cycle, including on the hydrocarbon production, more than 3%. And I can confirm you. We had a 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 '25 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.