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.

Good morning, good afternoon everyone. Patrick Pouyanné here together with Jean-Pierre. Nice to be with you again after seeing many of you in person at our Investor Day in New York earlier this month. I just spent the last three weeks on road shows. I would like to share with you that we received constructive feedback from investors on our balanced strategy and the level of understanding of our growth profile on both pillars, oil and gas. This was evidenced by the quality and depth of our upstream portfolio on one side, and on the other side, the integrated power is now better understood on both sides of the Atlantic. As discussed at the Investor Day, the clarity and consistency of our strategy must remain our priority. Discipline on cost, maintaining a low breakeven portfolio, and a strong balance sheet supporting attractive shareholder returns are fundamental principles that allow the company to be resilient through cycles, especially as we enter an increasingly volatile environment, as we have seen during this third quarter. I will not take up more time and will hand over to Jean-Pierre to discuss the details of the third quarter financials, which I believe demonstrate the resiliency of our integrated model in a challenging environment for oil and refining margins. We will be happy to answer your questions during the Q&A.

Thank you, Patrick, and good morning, good afternoon everyone. This quarter, we faced a more challenging environment with refining margins sharply deteriorating; the European refining margin marker was down by 66% quarter-to-quarter and was 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’s average LNG price decreased by 6%. In this context, the company reported adjusted net income of $4.1 billion for the quarter and $13.9 billion over the first nine months of the year. Profitability remained robust with a return on average capital employed for the 12 months ending in September at 14.6%. Now moving to the business segment, starting with the first pillar of our balanced strategy, 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 to 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 in Ichthys LNG and security-related disruptions in Libya. Additionally, during the third quarter, we achieved first oil at the high-margin Suncor project in the Gulf of Mexico in the U.S. and first gas at the Fénix field offshore in Argentina. We expect production for the fourth quarter of 2024 to be between 2.4 and 2.45 million barrels of oil equivalent per day, benefiting from the end of security-related disruptions in Libya and yesterday's startup of the Mero 3 project in Brazil that compensates for several plant shutdowns during the fourth quarter of 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 the GranMorgu project, which has a capacity of 220 barrels per day. This FPSO is located offshore Suriname with estimated recoverable oil reserves of more than 750 million barrels. These low-cost, low-emission developments were sanctioned one year after the end of appraisal and are designed to accommodate future timing opportunities to extend the production plateau. GranMorgu is accompanying six major oil and gas FIDs of 2024, all of which de-risk our medium-term production growth objective of 3% per year through 2030, which ultimately translates into growing shareholder distributions. Exploration and production ASC932 OpEx per barrel equivalents remain best-in-class at $4.9 per barrel for the first nine months of 2024, compared to our objective of being below $5 per barrel. Moving to integrated LNG: first on the results, hydrocarbon production for LNG decreased 7% quarter-to-quarter, primarily linked to unplanned maintenance on Ichthys LNG. On the other hand, LNG sales increased by 8% quarter-to-quarter in the context of seasonal inventory replenishments. Integrated LNG adjusted net operating income was $1.1 billion in the third quarter, with results primarily reflecting 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 of dividend payments from some equity affiliates of around $200 million. Looking ahead, given the evolution of oil and gas prices in 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 of 2024, slightly higher than the $9.9 per million BTU in the third quarter. During the third quarter, TotalEnergies strengthened future cash flows by signing several medium-term sales contracts in Asia, bringing the total Asian LNG contracts signed year-to-year to 4 million tons. In addition, we are enhancing the integration along the gas value chain by acquiring low-cost upstream dry gas supply in the Eagle Ford in Texas. Moving now to Integrated Power. Overall, 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%, in line with annual guidance of more than $2.5 billion, contributing to the resiliency of the company. We achieved several milestones during the third quarter, the first being the startup of two giant solar farms in the U.S. with battery storage in the fast-growing ERCOT market in Texas, where we already have all the necessary building blocks that define our differentiated integrated model. We closed on the strategic CCGT acquisition located in deregulated UK markets that complements our existing intermittent renewable assets. 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 sharp decrease in global refining margins in Europe, which fell 66% sequentially. The rest of the world's refining markets also fell to $15 per ton in Q3 due to normalization of trade flows after the Russian ban and ample supply relative to recent capacity increases. Currently, it is close to $25 per ton. This indicator, $15 per ton, is lower than our breakeven at $25 per ton, and we also suffered some incidents in some of our refineries. For the fourth quarter of 2024, the company anticipates the refining utilization rate will remain above 85%, with a turnaround planned at the Leuna refinery in October. Marketing and services results remained strong for the third quarter with adjusted net operating income of $0.4 billion and cash flow of $0.6 billion. At the company level, to wrap up, in the third quarter, we reported $1.1 billion of negative adjustments to net income related to impairments, linked to two events: the Chapter 11 bankruptcy filing of SunPower in the U.S. and the exit from Blocks 11B, 12B, and 567 in South Africa. After the bid reported in the first quarter, the first working capital release was reported during the second quarter, and a new release of $0.4 billion was reported this quarter. 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 2024. As I stated in the introduction, profitability remains robust with a return on average capital employed at 14.6%. Capital discipline is strong. We confirm 2024 net investment guidance of $17 billion to $18 billion. Lastly, we continue our track record of strong shareholder distribution. Buybacks are consistent with the company aiming to execute yet another $2 billion in the first quarter, in line with the objective of $8 billion for the full year. Dividend growth is healthy, with the third interim dividends up nearly 77% compared to 2023 and up 20% compared to pre-COVID levels. We will stop here, and with that, Patrick and I are available to answer your questions.

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

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

On cash flow, Jean-Pierre mentioned in his speech that there was – we had a lag effect.

A lag effect.

A lag effect on some SMEs between the results and the cash dividends, mainly LNG SMEs. So, that's why it is affecting the integrated LNG cash flow in Nigeria, in Qatar. But I think this is not something we should overanalyze. In fact, there is no fundamental reason to have such a difference. It's just a quarterly effect. On the second question, yes, I learned that. I mean we have quite a lot, as you know, of acreage in Argentina. We know that we manage it quite cautiously. We just recirculated CapEx cash flow. We mainly produce gas. We have some acreage exactly like Exxon in the oil window, which until now we did not develop. In fact, it's a question of CapEx. We know it's a question mark within our company to know if we will move from allocating CapEx more towards the oil window and less on the gas. But that would require some investment. So, we are evaluating our options. Having said that, we do not intend to invest more as long as Argentina remains a specific country where you cannot repatriate dividends freely. So, as long as this remains the same, as I explained to the Argentinean President when I met him last month, we want our money back. So, we will not invest more as long as we do not see the freedom to repatriate dividends. Again, we have a large portfolio, and 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 my view.

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

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

Okay, thank you, Michele. Uganda is progressing as per plan. We intend to start production by mid-2026. The drilling is positive, I would say. The news from the reservoir point of view is generally positive. So, I would say it is progressing. The pipeline itself is being built and laid. So, I would say we are on the way to deliver this important project, not only in terms of production but also in terms of cash flow for the company; it is quite a sizable investment. That's where we are on Uganda. On Mozambique, we need to consider various aspects. One of them has been security. On that front, it has progressed. Of course, the stability of political power in Mozambique is important for us. We are following the news from there and we intend to visit the country when it is ready. The more stability that comes, the better it will be for everyone. However, we are currently more focused on the northern part, Cabo Delgado. Following the election process, we have received good feedback, and it was quiet with no major events during that period. Therefore, from this perspective, I would say we are positive. However, as I told you last time, we are also working on financing for the project. There is a significant project financing package that was executed in 2020-2021 and had begun to be executed in 2021 before the force majeure. All credit-export agencies have done their due diligence on the projects, and technically, everything is in place. Now we are waiting for the green lights from some G7 credit agencies, and we are actively working to secure these. So from my perspective, we are on the right track. Regarding COP29, honestly, I don't see many advancements. I will personally be there because I am one of the three champions of the oil and gas decarbonization charter, alongside Sultan Al Jaber and Amin Nasser. We plan to have an event there. This is, by the way, an interesting collective movement for the industry. We have engaged with 52 companies, including numerous national oil companies, and it is a significant step forward to implementing a reporting framework similar to ours. We need to share best practices in terms of methane emissions, which is one of our objectives. I think that is positive. Regarding COP29, I’m not part of the discussions; from what I've heard, we don’t expect much new information. One key area in which we would like to see progress is on carbon credits and Article 6. Establishing a strong framework that will be validated by the UN and the international community would be crucial for investing in that field. That sums up our main expectations.

Thank you.

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

Hi, Jean. Thanks for taking the questions. Two, if I could, please. First, just coming back to your early comments on cash flow generation in the quarter. I mean, obviously, CFFO can fluctuate and there can be phasing effects quarter-on-quarter. I just wonder if you could talk about year-to-date performance and how it compares with your beginning of year expectations on an underlying basis? And then secondly, the capital frame was made very clear in October with the Investor Day. Given the short-term macro volatility to the downside as well as 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 that you talked about? Thank you.

Okay. First, on the cash generation, I would say on the cash flow after nine months, we are at $23 billion, next to 2023. This means we are today at roughly $30 billion. We could land at the end of the year around $31 billion, which is, in fact, aligned with our expectations. We were at $31 billion, $32 billion. We had higher expectations in particular regarding the refining margins. So, from my global perspective, it does not change the guidance we gave you at the last CMD in New York, including for share buybacks. I am comfortable with our trajectory; we are on track with our anticipation at $30 billion. Can you discuss CapEx? The CapEx trend I see for the $2 billion isn’t at $70 changing our strategy. At $70, when we speak about short-term, short-cycle CapEx, $70 gives us a quick payback. The change in strategy only occurs when we go down to $50-$60 per barrel, at which point we could consider activating part of this flexibility and arbitrating some of these short-cycle CapEx, as the payback from these additional wells will be longer. I see no difference between $70 and $90. The market today seems to have settled to around $70. However, from this perspective, the guidance we previously gave at CMD still stands. Just to clarify, Jean-Pierre mentioned $17 billion to $18 billion for the year 2024; it was not $16 billion to $18 billion. For next year, we expect to be in the range of $16 billion to $18 billion with $18 billion being organic CapEx.

Super. Thank you, Patrick.

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

Thank you very much. Good morning. My first question is on refining; obviously, a very weak quarter. Patrick, you have said before that you are not positive about the business. But do you see grounds for optimism that, as the class starts return 2.2 million barrels a day to the market, margins could strengthen meaningfully from the current $25, which I believe is your breakeven level? My second question is 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 in 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? Thank you.

Okay. First, on refining, the average margin can be gauged using different metrics. It is around $35 per ton from 2013-2023. By the way, this is the planning assumption we use internally for the long term. It is $35 per ton, which is higher than the current $25. That is why we are working hard to have this breakeven go down to $25 per ton. I am moderately optimistic as a result. We benefited from two years of COVID disruptions in 2021, resulting in a significant number of refinery shutdowns in the Atlantic basins, particularly in the Caribbean Islands and the U.S. However, we are now seeing a dislocation of the market due to shifts in Russian flows, which have contributed to pushing margins upward. Typically, whenever price margins are high, there's a tendency for operators to halt restructuring efforts, particularly in Europe, where we have seen some smaller refineries that were supposed to shut down being maintained. Additionally, some new refineries have begun operations, particularly in China. This has added to supply pressures. In Europe, we face the further obstacle of some products being imported from the U.S., which is complicated by the fact that Russian products are now heading to South America. Lastly, market demand in Europe is not strong at the moment, so we are being challenged by a cyclical backtrack. Fundamentally, true, we have too many small refineries in Europe, and the industry needs to rationalize its capacity. As you know, one of the strategies is to transform these small refineries into biorefineries, keeping in mind that in Europe we benefit somewhat from regulations that promote biofuels to foster greater demand for these alternative energy sources. Thus, I am moderately optimistic about future margins but will be pleasantly surprised if I witness more refinery shutdown announcements. On the LNG side, I am uncertain where the suggestion of a two-year delay arose. I was clear in New York, stating that we believe the next wave of capacity will likely not commence until 2027. I do not recall mentioning 2025 as a start date. There has been a discussion regarding the timing between 2026 and 2027. We observe several projects in the U.S. experiencing delays for various reasons. To summarize, while we're accepting of a 10%/year additional capacity growth starting in 2026 or potentially 2027, we see no new supply emerging in 2025 that would shift market fundamentals. In 2025, I would expect TTF to average $12 per million BTU, as we don’t see any new capacities fundamentally changing a market already under significant stress.

Thank you.

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

Thank you very much. Good afternoon. Just two questions on renewables, please. 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.

The first one is quite easy. We had an option negotiated with RWE because, as you’ve noticed, we made a farming into the Dutch offshore wind project in connection with our goal to decarbonize our Zeeland Refinery through green hydrogen. RWE was successful in acquiring two offshore wind licenses with a low cost of entry, and, of course, it would be counterintuitive not to exercise our option. That helped boost our standing in growing globally. So I think driving down costs will happen by scaling these developments together. We are looking closely at RWE, as they are also a strategic partner for us to grow our global footprint. Regarding corporate acquisitions, I would prefer not to comment on my competitors' moves. Every company has its own strategy. Our competitors in Norway are very focused on offshore wind; it could be a good model. However, we remain committed to developing our offshore wind assets organically, and we have no intentions of acquiring a minority stake in a competitor without a defined industrial strategy.

Understood. Thank you.

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

Hey, I wanted to get back to the question that Irene asked about refining margins specifically in Europe, because there are quite a lot of indications that we've seen 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, it seems that this is not the case for the Total portfolio. So I just want to confirm; margins have declined quite a bit, but they’re not low enough for you to consider any economic run cuts, right? That was the first I wanted to ask. And the second one is about the balance sheet. Last quarter, gearing was at 10%. During the earnings call, you talked about the underlying level of about 7% to 8% if you cleaned up a few noisy items. We’re now at 12%. What explains the difference between the level of 7% to 8% that was mentioned last quarter and now 12%, and how do you expect that to develop over the next one or two quarters, please?

On refining margins, honestly, I’m not sure we are large enough to consider running cuts simply to please our competitors. There is no OPEC for European refiners, so I mean we are at the breakeven margin today. It’s important to assess the impact of fixed and variable costs. As long as the margin is above variable costs, we prefer running our refineries to cover some of our fixed costs. However, we are covering our variable costs comfortably, so that’s the economic answer. But I believe much of this is more about structural weaknesses and the necessity to transform refineries, taking into account their location and market characteristics. We have six or seven refineries in Europe. We know each of these assets, and we will be looking to transform them over time. Regarding gearing; I believe our levels were recently at 7% or 8%. All of this has changed since last quarter due to numerous factors; primarily, we experienced high investments and acquisitions but will seek to rebalance in due course. We anticipate a working capital release of $2 billion for the next quarter, which is in alignment with guidance we gave at the beginning of the year. We anticipate returning to a level of around 10% to 12% gearing by the end of the year, assuming the price environment remains consistent with today’s conditions.

Wonderful, thank you.

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

Good morning, everyone. Patrick, I know you've been asked extensively about refining this morning, but I want to ask the same question a little differently. Some of your peers have started to consider shutting refiners when they face a major capital event like a turnaround. In light of the anticipated extended downturn in refining operations, are there any assets you would consider rationalizing at this point if this continues?

Again, we've done it before with Le Mans in 2015 and Grand Prix in 2020. It is clear that we carefully look at the timing of shutdowns to avoid hefty expenses on a refinery we soon intend to shut down again. Turnarounds are part of the normal cycle occurring every four to five years, or even every two years for some refineries. Still, a decision to shutter a plant is normally based on structural weaknesses, market relevance, and location. If the first parties to shut down are smaller refineries lacking efficiency, I expect that will be the case.

Terrific. Thanks so much.

The next question is from an unidentified analyst from Bank of America. Please go ahead.

Hi. Thanks for taking my question. I just had one related to the cash flow from operations that you had at the start of this year, which you gave guidance of around $34 billion. The macro environment that you showed then versus what we've seen is not that different. Obviously, refining has been weaker. Is there a way to help me bridge the gap between the $34 billion that you originally envisioned and the $30 billion or so that you mentioned today? Any moving parts there would be helpful. Thank you.

I don't remember $34 billion; I had $32 billion in mind. However, clearly, gas prices were lower than expected during the first half of the year, which has affected our forecast. We dipped under $10 per million BTU during that first half. The European inventories were fully replenished, creating seasonal effects that are now aligned with our anticipations around $12-$13 per million BTU. This affects our gas trading and LNG activities, enabling a forecasted $1 billion drop from what we might have anticipated prior. In addition, refining performance has decreased. I believe we are losing around $500 million on that front. But we will assess all these losses accurately as the year progresses.

Okay, that's fine. Thank you.

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

Yes, thanks very much. A couple as well, if I might. I wanted to focus on Nigeria for a moment. Firstly, Patrick, can you just remind me where we are with the sale of the onshore assets to Chappal? Is that expected to complete soon? Where are things with the authorities? Also, could you make any comment on Train 7 and its development and timing? And just generally on gas close to Nigeria LNG and how those have been progressing through the year and what that might have an impact on your off-take?

Okay. On the onshore assets, we have progressed. I believe we have received some approval. Recently, the regulator instructed us that we should have a green light soon. We are not in the same position as some of our peers because we are not operating and hold a non-operating position. That means it's easier for authorities to evaluate the quality of the buyer because we’re a non-operator. Regarding Train 7, we've been working hard over the last year to agree the right terms to develop gas projects required to supply Train 7. We are making good progress and have secured improvements, particularly on the transfer gas price from the upstream to the downstream. We sanctioned the first project, Ubeta, this year to fill Train 7. We are also working to sanction another one, IMA, which is planned for 2025. There are opportunities for monetizing gas reserves as the authorities make efforts to promote gas developments.

Can I just push you a bit more on Nigeria? What is the current timeline for Train 7 to come online?

Train 7 is expected to start by the end of 2026, but it is one of the projects that is less likely to advance. To clarify, the schedule could stretch between 2026 and 2027. Having said that, as we develop gas, we do not need to have Train 7 completed before we begin.

Okay, thank you.

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

Hi, thanks for taking my questions. I've got two, please. First on the outage at Ichthys LNG: you've talked a lot about preventive maintenance to avoid unplanned outages. Is there a way that this issue with the heat exchanger could have been avoided? 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, which is around $100 million? 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 higher interest rates? Thank you.

Kim, I'm sorry, but I'm not in charge of the day-to-day operations of the company. Incidentally, we are not operating Ichthys, so something happened there has been resolved by those directly in charge of operations. I am sure that our Australian teams are working hard to gather lessons learned to avoid such issues in the future.

Yes, for the time being, we have a solid portfolio with costs under 4% globally. Thus, I do not see the need for refinance. We made two successful bond issues in the U.S. market this year, one in April and another in September, due to oversubscription and completed successfully for very long maturities. Therefore, our strategy is to continue working on long-term maturities, with terms of 30 to 40 years.

Just before we take the next question, I would like to clarify an earlier point. If Biraj is still online, I want to confirm that you are correct: the expectation was $34 billion, but we are more aligned with $30 billion to $31 billion at year-end. The drop, as I previously mentioned, mainly arose from lower gas prices and trading issues. I can quantify the decrease from the trading aspect being around $1 billion.

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

Thank you for the update. Two questions, please. The first one, actually just a quick follow-up on the comments around the CFFO generation in the year. I was wondering if the Chemicals segment is also an area where you've seen lower cash flow than expected based on a combination of the macro and perhaps slower ramp-up of your projects or underlying performances elsewhere in the business? Secondly, on the Integrated Power segment, ROACE dipped below 10% this quarter. How quickly should we expect that ROACE to return above the 10% level?

The second question is fairly easy. It is linked to the calendar of the farm downs. As I told you earlier, farm downs in renewables significantly impact the capital employed. Thus, as those transactions are planned for the fourth quarter, we can expect some improvement on financial metrics. We should reach this metric around 9.5-9.8% shortly. That would be the main reason for the dip; it’s primarily due to capital employed tied up in the farm down schedule. On chemicals, you are likely following some chemical companies. We are focused on petrochemicals and polymers. The margins in Europe have been low for numerous quarters. The global margins aren’t strong either, due to increased Chinese capacities and ample supply generated by several petrochemical projects in the U.S. funded by low-cost ethane resources. These capacity expansions were mainly targeting export markets. Therefore, we are experiencing a situation where this increased supply affects pricing in Europe. Thus, I would say we currently have reasonable performance but are not experiencing high market cycles. The market is undergoing adjustments due to weak demand driven by a global economic downturn according to IMF forecasts, which negatively impacts our chemical business performance in Europe, thus limiting our profitability.

Thank you.

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

Thank you. Good afternoon or good morning. Patrick, just curious about the Integrated Power business. Can you give us a better understanding of the contribution to your earnings or CFFO between the gas-fired power portfolio and the renewable power portfolio? Thank you.

Yes. And you forgot about the customer portfolio because there are three segments of revenue or contribution. One-third comes from renewables, one-third from gas plants, and one-third from customers. This will give you a rough rule-of-thumb for how the CFFO is derived today.

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

On PNG LNG, we have been very transparent. We halted the tender process due to high CapEx. We halted the discussions and have re-evaluated the designs to streamline the costs. We are working with contractors, particularly from Asia. The tendering process has begun to find new contractors and also launched a new optimized design. We expect to receive offers by the summer of 2025.

Okay, thank you.

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

Hi there, and thanks for taking my question. I just have one left really, and that's just on the bio business, which I think you've referred to a couple of times. Europe is clearly incentivizing biofuel use. However, there has been considerably increased capacity added, and an even greater number of brownfield conversions. Are you confident that there's going to be sufficient demand in Europe and the U.S. to absorb this supply over the next two to three years as we currently see weak margins?

This is precisely why I was answering earlier regarding the supply-demand dynamics. The European market is entirely regulated; therefore, pricing reflects regulation. The current low margins stem from actions taken in specific countries, like Sweden and Finland, which shifted their biodiesel mandates. Consequently, we faced oversupply and declining HVO margins. So we are monitoring these developments closely. We don't need to commit to increasing supply readily. We remain cautious as future plans are made, recognizing that not all measures announced will be legally mandated. While I trust only the legally binding minimum mandates which tend to be reliable, voluntary targets can be questionable regarding whether they can maintain sustained demand.

That's great. Thanks for your answer.

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

Yes. Hey, it's Jason Gabelman from TD Cowen. I had two questions. The first is on Russia: 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.

I hope you are correct in your assumption. The war would not only end for TotalEnergies but, more importantly, for the peace of our continent, which would positively influence the global economy. So, in terms of specifics, Novatek dividends were around $600 million per year, which are primarily tied up in their accounts. This leads to a potential recovery estimate of $1 billion. Additionally, ties to the Yamal dividends also effect some cash flow, which could contribute another $500 million. So, I would estimate total cash tied up to be somewhere between $1.5 billion to $2 billion.

That's helpful. Thanks. Turning to CapEx, it looks like if you continue the pace of organic spending from 3Q, you’ll breach the high end of guidance for the full year. I know there are some inorganic acquisitions out there, such as 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.

No, we will not breach. We previously confirmed our guidance of $17 billion to $18 billion. Just to be transparent, organic CapEx by the end of September were roughly $12.5 billion; if we add another $3 billion to $4 billion, we will go to $16.5 billion. That accounts for M&A and other acquisitions. That means our expectations remain firmly rooted. Our estimates show we are currently on track at around $14 billion by the end of September. Thus, on a net basis, I confirm we are aligned with our CapEx expectations. Just to clarify: I include the possibility that we could close the OMV acquisition in Malaysia, but that process is not fully within our control. We are presently at $12.5 billion organic, which means we are not reaching the upper limit of our $18 billion overall guidance.

Great, thanks.

Thank you, everyone, for joining us today. In summary, this quarter was less robust than previous ones, primarily due to challenges in refining margins, but we remain confident about our ability to deliver on our goals. We affirm our expectations for a strong year-end in line with board guidance for shareholder returns and are optimistic about 2025, which will showcase a growth cycle with an increase in hydrocarbon production. Moreover, I can confirm that the Mero-3 project startup will significantly contribute to our growth ambitions. Thank you for your support, and I look forward to our next meeting.

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