Ladies and gentlemen, welcome to the Third Quarter 2022 Results Conference Call. I now hand over to Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

Thank you. Hello, everyone. Jean-Pierre speaking. We reported solid third quarter results that demonstrate TotalEnergies' ability to effectively leverage the very strong and volatile environment. This success allows us to strengthen the balance sheet and share the benefits with our employees and shareholders. The third quarter environment was marked by high volatility. Brand prices averaged more than $100 per barrel in the fourth quarter and rebounded late in the quarter after OPEC+ announced a $2 million per barrel cut in early October, showing that OPEC wants to maintain control despite the risk of lower world economic growth. European gas prices soared due to increasing geopolitical tensions and the risk of insufficient supply during winter, although this risk is limited as gas storage in Europe is full. Consequently, NBP nearly doubled in the third quarter to over $42 per MBtu. A key factor driving our results is our average LNG price, which was lifted by the spike in natural gas prices and reached a record $21.5 per MBtu in the third quarter, an increase of more than 50% from the previous quarter. We fully captured the benefits of this LNG price because of our integrated strategy. European refining margins, NCV, although energy costs increased, reached $100 per tonne in the third quarter, still among the highest we've ever seen, but down from record-setting levels close to $150 per tonne in the previous quarter. In this context, the company generated third-quarter adjusted net income of $9.9 billion, or $3.83 per share, consistent with the previous quarter. These strong results were achieved despite increased taxes, which I will discuss shortly, as well as a decrease in production and oil prices, offset by higher integrated LNG results. Debt-adjusted cash flow was $12 billion for the third quarter, down 12% from the second quarter, mainly due to a lag effect in dividends received from equity affiliates. Year-to-date, free cash flow stands at $38 billion, an increase of 80% compared to last year. This level of cash flow generation marks the beginning of a new era for the company, characterized by a zero net debt balance sheet, accelerated transition to a multi-energy future, and an increase in cash flow payouts for shareholders to 35% to 40% from 2022. These were the key messages from our strategy and outlook presentation last month, and the third quarter results confirm them. The effective tax rate increased to 44% in the third quarter from 39% in the second quarter, largely due to a higher tax rate for exploration and production activities resulting from the UK energy profit levy, which impacted the quarter by $0.6 billion for four months of taxation. Despite increased taxes, which totaled $26 billion paid by the end of September, mostly in producing countries, our cash flow generation remains significantly stronger than we projected a year ago, thanks to favorable price conditions. We estimate the EU solidarity tax impact at around €1 billion. Operationally, the company's hydrocarbon production was 2.7 million barrels of oil equivalent per day, reflecting a 2.5% decrease from the previous quarter, primarily due to planned maintenance and unplanned downtime at Kashagan, partially offset by new production from Sepia and Atapu, as well as ramping up Mero 1 in Brazil. Year-to-date, operating expenses are trending to $5.6 per barrel on average, which includes higher energy costs amounting to $0.25 per barrel. Aside from these higher energy costs, we are not observing significant cost inflation at the operational expense level. Cost discipline remains a top priority. We are in a commodity business, and maintaining a low breakeven is crucial for navigating the cycle. Now, let’s look at the results by segment. Integrated gas, renewable, and power reported record adjusted net operating income of $3.6 billion this quarter, an increase of $1.1 billion from the second quarter, with cash flow of $2.7 billion driven by higher LNG prices and strong trading activities comparable to the prior quarter. The favorable environment allowed us to overcome the quarter-to-quarter 10% decrease in LNG sales resulting mainly from the Freeport LNG outage and planned maintenance at Ichthys LNG. We expect fourth quarter LNG prices to be above $17 per MMBtu, still at high levels. I remind you that 70% is linked to Brent formula and 30% to gas spot index. The company continued executing its LNG growth strategy by acquiring a stake in the North Field South LNG project in Qatar after the Northeast LNG acquisition last June. In the electricity sector, renewable power generation capacity reached 16 gigawatts at the end of the third quarter, up 4.4 gigawatts in the quarter, including 3.8 gigawatts from the Clearway acquisition and the launch of the Seagreen offshore wind farm in Scotland. We completed the acquisition of 50% of Clearway Energy in the US and announced another significant acquisition in renewable energy in Brazil yesterday. Net electricity production was 8.8 terawatt-hours in the fourth quarter, up 10% from the second quarter, driven by high utilization rates and increased renewable power generation. EBITDA from the electricity and renewable segment was $160 million in the third quarter, stable compared to the prior quarter. Operating cash flow for integrated gas, renewable, and power was $4.4 billion in the fourth quarter, including a positive impact on working capital due to reduced margin growth and seasonal factors in the gas and power supply business. The exploration and production segment achieved adjusted net operating income of $4.2 billion and cash flow of $6.4 billion in the third quarter, declining by about $0.5 billion and $1 billion, respectively, compared to the previous quarter, due to lower production. The average realized liquid price fell by nearly $10 per barrel quarter-to-quarter, but our average realized gas price rose by about $6 per MBtu. We are increasing activities in exploration and production, especially with the start-up of production at the Ikike field in Nigeria, the launch of the Begonia project in Angola, and the Fenix project in Argentina, as well as a significant gas discovery in Cyprus. The combined Downstream segment generated adjusted net income of $2.4 billion and $2.9 billion in cash flow in the third quarter, an exceptional performance even if it decreased from second quarter records, benefiting from strong distillate margins and solid trading results similar to the previous quarter. To put this in perspective, in the first nine months, Downstream generated $8.4 billion in cash flow, double the amount from the same period last year, more than enough to cover the entire regular dividend for the year. We expect refining margins to remain strong, especially for distillates due to the ban on imports of Russian petroleum products into Europe, effective February 2023. For the first nine months of 2022, we generated operating cash flows before working capital changes of around $37 billion, up 85% from the same period last year. Our year-to-date net investments of $12.5 billion align with our guidance of $16 billion for the year, including $4 billion in decarbonized energy. We've repurchased $5 billion in shares over the first nine months and plan an additional $2 billion buyback in the first quarter. Our gearing ratio has decreased to 4% at the end of the third quarter. Given our strong financial position and cash flow generation, the company expects a balanced value-sharing policy, including an exceptional bonus of one month’s salary for all employees worldwide, along with the new shareholder return policy introduced in September targeting 35% to 40% cash flow payouts. In addition to the regular third interim dividend of €0.69 per share, representing a 5% increase year-over-year, the Board has set the ex-dividend and payment dates for the interim special dividend of €1 per share in December 2022. This concludes my comments. Now, we can proceed to the Q&A.

The first question is from Irene Himona with Societe Generale. Please go ahead.

Thank you very much. Good afternoon Jean-Pierre. I have two questions. First, you mentioned a significant $7 billion working capital release in the third quarter. Could you elaborate on the main components? Also, what can we expect for Q4? Any guidance would be appreciated. Secondly, regarding the Russian impairments you reported this quarter, can you remind us of the net book value remaining after these impairments? Since the strategy you presented last month excluded everything related to Russia, will you eventually write off whatever is left on the balance sheet? Thank you.

Thank you, Irene, and good afternoon. The first question is about working capital. We reported a $6.7 billion release in working capital during the third quarter, and there are three main reasons for this performance. First, we had a $3 billion working capital release due to the price effect on stocks. Second, there was a $2.4 billion release linked to the valuation margin release in our gas and electricity business due to optimization and exposure reduction actions. Lastly, we saw a $2.1 billion release related to our E&P tax payable, primarily in Norway and the UK. On the downside, we experienced a $0.8 billion reduction due to various effects on payables and receivables. Looking ahead to the first quarter, it will largely depend on price movements for stock valuation and gas and electricity margin variations, but I expect that most of the tax will not be settled in 2022, rather in the first quarter of 2023. Therefore, I do not anticipate a significant cash outflow or reversal of this performance in the fourth quarter given the current situation. Regarding impairments, our accounts will reflect an additional $3.1 billion due to the valuation of our shares in the third quarter as we reassess long-term cash flow scenarios with increased uncertainties about cash transfers from Russia. This has been the main cause of the impairments. We recorded a total of $11 billion in impairments, including $4.1 billion in the first quarter and approximately $3 billion or $3.5 billion in Q2, with an additional $3.5 billion this quarter. As a result, we have about $6 billion in capital employed for Russia after accounting for these impairments.

Very clear. Thank you very much, Jean-Pierre.

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

Thank you very much Jean-Pierre for all the presentation and the strong set of results. Two key questions from me. The first one on the LNG side, there were exceptional results this quarter despite the effect that there are quite a few shutdowns. And I was wondering if perhaps you could give us visibility of when you expect some of this production to come back, especially Freeport, Nigeria LNG, and Ichthys returning back from scheduled maintenance. And then my second question is on your GHG emissions, always very helpful to have it on a quarterly basis, and ongoing strong delivery, especially in the reduction of Scope 3. But there was a 10% increase in Scope 1 and 2 emissions. My understanding is most of it comes from Europe and the ramp-up of CCGTs and the Dutch refinery. But I was wondering if you could give a bit more visibility on that. Thank you.

I will begin with the second question. I want to be very clear that the increase in Scope 1 and 2 emissions in Europe is entirely linked to the CCGT. In 2015, we did not have any CCGT in our portfolio, but now we have several in France, Spain, and Belgium. We started a new facility in France at the beginning of this year. For obvious reasons, the CCGT performed particularly well during the third quarter, which is the reason behind the increase in Scope 1 and 2 emissions in Europe. Regarding your second question about our strong LNG results despite the slowdowns, this shows the success of our integrated strategy for LNG as we maintained high performance in this segment even during shutdowns. From what I understand, Freeport is expected to return to 100% capacity before December this year, Nigeria is likely to return next year, and their shutdown has been completed, so they are expected to resume normal production in the fourth quarter.

Thank you.

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

Hi, I've got two questions. First, could you share your thoughts on the impact of the refinery strikes in France during the quarter and how that might affect fourth quarter results? Secondly, I heard your comments regarding distillate cracks and their potential support due to the EU import embargo on Russian oil. This remains a complex issue, and I would like to understand more broadly what you foresee as the impact of the EU embargo on Russian oil for both crude and products in the coming months.

The impact of the refinery strike in France is difficult to quantify. While we did lose production in France from these refineries, we gained from improved margins in our refineries, especially in Belgium and Germany. Therefore, I won't provide a specific figure. The effect of the strikes in France during October is minimal. France remains strong this year. We believe that the upcoming ban on Russian petroleum products in February 2023 will support high distillate cracks, and it will be challenging for Europe to make up for the lost volumes. Hence, we expect margins to stay elevated. In terms of crude, it's somewhat easier to offset the effects of the ban on Russian crude, effective in December, since crude can be sourced from other countries. However, it's important to note that these bans will likely bolster prices, as Russian crude will need to find new buyers, primarily in India, Brazil, China, and Asia, which will benefit from discounted crude. Conversely, European refiners will have to pay a premium to secure new crude supplies. This is the expected impact of the EU ban.

Okay. Wonderful. Thank you.

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

Thank you very much. Most of my questions have been answered already. So maybe just a quick one, Jean-Pierre, if you wouldn't mind giving us a bit more detail about what you're seeing in terms of demand destruction in your chemicals business and perhaps in your overall sales figures, and how you're looking into next year considering the recession that's coming at us.

Honestly, it's too early, too premature or too early, I think, to give a figure. In chemicals, we started seeing, but marginally the impact of the possible recession that could happen next year. On our sales at present time, honestly, given the discounts we have in our retail section, we don't see any drop in volume. So we foresee an outlook for next year to have an impact on chemicals and on gas as well, but it's too early to give precise figures.

Fair enough. Thank you very much.

The next question is from Oswald Clint with Bernstein. Please go ahead.

Yes, thank you, Jean-Pierre. I would like to ask about the LNG side. Can you help clarify how you are performing so well? There were significant gas price differentials during the quarter, particularly at the end, which need to be marked to market. Additionally, I understand you have been actively purchasing spot LNG cargoes in the quarter. Are you experiencing losses on hedge deliveries that you are offsetting with profits from these new spot cargoes? Also, while I recognize the confidentiality surrounding assets in Qatar, could you provide any insight on the potential EBITDA increase we might expect from the recent startup of one of the largest solar plants in the world this month? Will this be a significant factor as we look into next year? Thank you.

Okay. So our performance regarding LNG, I think 2021 definitely marked the start of a new real performance for this LNG and electricity trading. This business segment, quarter-after-quarter, very replicates very strong performance. Of course, we do not provide full details or absolute value for our trading business. But what I can tell you is that we were able to replicate LNG gas and power trading performances very high through Q2 of 2022. In Q2 2022, we replicated the high performance we had in the fourth quarter of 2021. Perhaps you remember that in the first quarter of 2022, we announced that we had a very, very high trading performance, and we qualified this performance as a lower performance of more than $500 million. That being said, it is true that we have to record in the Q3 results the impact of the Freeport outage. As well as the loss of cargoes due to the fact that we had to offset hedging losses. However, our ability to deliver a very good level of performance demonstrates that we have an evolved global portfolio. We must assess these hedging losses. We have LNG production in almost all the main hubs, including the US, Qatar, and Australia. Of course, we also have energy coming from Russia. Given this portfolio and given the outlet we have, we managed to balance sources and outlets. This is how our trading is able to deliver, once again, outstanding performance quarter-on-quarter. Regarding Qatar, yes. The solar farm was inaugurated last week; it is, globally, one of the most sizable solar farms worldwide. I think it represents 800 megawatts. I do not have the EBITDA figures yet, but I will ask my team, and we can get back to you with those figures.

Very clear. Thank you.

The next question is from Lydia Rainforth with Barclays. Please go ahead.

Thank you. And Jean-Pierre, good afternoon.

Good afternoon.

The first question relates to the strategy presentation, where the guidance indicated that gearing would reach 5% by year-end. It appears that you are already at that level by the end of this quarter, and I acknowledge the release of working capital and the write-downs. Can you provide an update on where you expect the gearing number to be at year-end? Additionally, regarding the broader perspective on renewables and the low carbon sector, we are also observing rising interest rates, yet there seems to be no difficulty in accessing financing and an increased focus on energy security. Do you believe these factors might alter the dynamics within some of the renewable businesses, potentially benefiting a company like TotalEnergies? Thank you.

Yes. So that's true that our gearing is already below 5%, with a net debt up to $5 billion around. It's difficult. You know that we do not have any magic figure in terms of per target. As a CFO, I would be more than happy to continue to strengthen my balance sheet and to continue to decrease the gearing. Having said that, in the first quarter, assuming that we continue to generate more or less the same level of cash flow from operations given our target CapEx at $16 billion globally for the full year, taking into account that we will continue our buyback program at $2 billion and pay the special dividend, representing more or less $2.5 billion, I would say that we should remain more or less in the same ballpark, around the 4%, or below 5%. Of course, it will depend on the working capital, but as mentioned, I do not anticipate a very strong variation for working capital. I would say we should remain more or less at the level we had at the end of September. Regarding renewables, it's not necessarily the same in the upstream sector. We have to face inflation and higher interest rates. But these additional costs, both inflation and higher interest rates, will be passed to the final customers when we negotiate the power purchase agreement. As we target these types of projects to have double-digit profitability, we have clear visibility on the leverage and cost of financing. We adjust the level of PPAs we are ready to sign in order to deliver the targeted double-digit profitability. So there is no miracle. With these interest rate increases and inflation, we don’t change the methods we use to sanction projects. On the opposite, we believe, this will be advantageous for TotalEnergies because it will eliminate less efficient competition.

All right. Thanks very much.

We have full energy, less competition. So it should be profitable for us, and it's positive for us.

The next question is from Bertrand Hodée with Kepler. Please go ahead.

Yes, I have just one question left. Coming back on your LNG trading performance, Jean-Pierre, you often refer to your integrated model. What in your view is making the difference? Is it because you have currently a very large access to re-gas capacity that you have secured that you are able, in fact, to maximize your LNG spot selling price? Or is there another reason for that outstanding performance?

Having acquired the LNG portfolio three or four years ago, we now have access to 18 million tons of trading capacity in Europe, representing more than 50% of the global capacity in that region. This provides a significant advantage for our traders to engage in arbitrage between the US and Europe, which is crucial for our LNG trading performance. Additionally, I want to highlight that we are the number one LNG exporter in the US, with over 10 million tons coming from there. This capacity enables us to supply our European customers using our re-gas facilities. We also manage overall LNG supplies in Asia, the Middle East, and have customers in India, allowing our traders to leverage the different markets. Given the LNG prices, each cargo can generate around $80 million to $100 million, which enables us to effectively maximize the value from this business.

Many thanks, Jean-Pierre.

The next question is from Alastair Syme with Citi.

Hi, Jean-Pierre, it's EU solidarity tax. You mentioned the €1 billion figure, but is this still an estimate and what clarity do you have? I mean you're clearly having some negotiations with different governments. So, I just wanted to understand where those negotiations stood? And then secondly, in the last few weeks, we've seen a bit of a collapse in spot gas prices in Europe. I know forward markets haven't changed as much. But do you have any perspective on why you think the spot gas prices have collapsed?

Yes. The EU solidarity tax will affect us in six European countries: France, Germany, Belgium, Luxembourg—primarily related to our refining activities—and also Denmark and France concerning our exploration and production activities. Currently, there are many uncertainties about how this tax will be implemented because the EU has provided a framework that each country needs to adjust according to local requirements. We've done a lot of analysis since there's significant uncertainty about the tax rate, as the EU has only specified a minimum rate and there's ambiguity about the use of tax loss carryforwards. Moreover, there's uncertainty about whether the basis will be from 2022 or 2023. Overall, we estimate that the EU solidarity tax will amount to approximately €1 billion for the entire year of 2022. Regarding the recent drop in EU gas prices, NBP is currently around $20 per MMBtu, compared to over $50 per MMBtu at the end of August, which is a substantial decrease. This drop is primarily due to reduced demand in Europe as a result of recent temperatures and a lower rig mix. Additionally, gas storage levels are nearly full. There is strong competition between EU and Chinese companies for energy cargoes to Europe, which has influenced these conditions. Furthermore, the situation in the UK—where storage capabilities are limited—has contributed to rerouting gas supplies to other European countries. Nonetheless, gas prices will largely depend on temperatures and conditions in Europe. With stocks full, we expect that winter 2022 shouldn't pose a significant issue for the EU, though there will be a need to use these stocks for winter 2023. Given the delays in Europe's capacity to fully make up for potential reductions in Russian gas supplies through pipelines, this should drive gas prices higher in Europe during that period. In the short term, the situation remains volatile, influenced by factors such as temperature and consumption. However, in the medium term, we will provide a message regarding our outlook for Europe, emphasizing our positive stance, especially for LNG gas.

Thank you. Can I just clarify on the solidarity tax? The €1 billion estimate, does that include the tax loss carryforwards, or is that a gross number before you would…

The tax; we made some calculations depending on the anticipation of what the tax would be depending on the countries.

Okay. If I…

In terms of solidarity tax, it depends on the country and the situation.

Thank you very much, and good afternoon, JP. I have a couple of questions and would like some clarification on windfall taxes. First, I want to revisit LNG and get a clearer understanding of the current hedging policy and how much of the portfolio is exposed. Patrick made it clear in New York that there is uncertainty regarding the longevity of contracts with Russian suppliers, which accounts for about 5 million tons per annum, and this uncertainty seems to be causing hesitation in hedging those volumes. Can you provide insights into how much the uncovered portion of your LNG trading portfolio has increased in recent months, and whether it will increase going into the fourth quarter? Are you therefore more exposed to volatility in spot pricing? Secondly, could you indicate any cash flows you receive from trading Russian LNG? Or is that too unpredictable to disclose as part of your cash flow from Russia? You've removed those cash flows when presenting your strategic view for the next five years, but they still seem to be included in your current data. Lastly, regarding the windfall tax estimate of $1 billion, can you clarify if that figure is prorated once those taxes become applicable? This estimate appears to be significantly lower than the figure mentioned during Strategy Day, where you included the UK component and discussed a much higher return.

Okay. Let me clarify this topic first. There are two different matters at hand. The first is the windfall tax profits in the UK, which is already in effect. The decision to implement this tax was made in July, retroactive to the end of May. We indicated in New York that at a rate of $35 per MBtu over the first quarter, this could amount to around €1 billion for 2022, covering the period from the end of May to the end of December. Therefore, we need to account for this in the UK, as it is certainly implemented. The only certainty we have is the MBtu and the production to which this tax will apply. So, it will be €1 billion or possibly less for this matter. By the end of September, we need to reflect over four months' worth of profits from the UK windfall tax in our records for the third quarter. The estimated impact is approximately $640 million. The second issue is the EU solidarity tax. Currently, there is nothing reflected in our accounts due to significant uncertainty around how this tax will be executed. The €1 billion figure I mentioned for the solidarity tax is the same as what we provided in New York. There are discussions regarding when this tax will need to be paid and the methodology involved, but it is expected to be a one-time charge, which is the key difference from the UK windfall tax, which is expected to remain applicable until 2025.

Great. Thank you.

Regarding LNG hedging policy, our policy is to hedge the following 12 months. That's what we have typically mentioned already to you many times, but with some exceptions. What has been mentioned regarding Russian assets is that we do no longer hedge Russian volumes since February 2022 to take into account the uncertainty you mentioned regarding access to the volumes. This is our policy. So a global policy, but with an exception in Russia.

Okay. And just to be clear on those volumes, I mean $5 million is the contractual element. There was a further 1 million tons that you said you'd committed to take in 2022. So we might take it that 6 million tons of LNG coming from Yamal at the present time is unhedged.

Yes, Yamal, because we hedge only the two first months. So the calculation is correct. In 2023, it will be something like 5 million tons of sales coming from Russia.

Okay, which will stay unhedged, but can you provide us with any indication about the indiscernible?

No. What we have given is a very compounded change since the publication of the registration documents indicating that our Russian upstream activities are able to generate cash. In the Q2 or Q3, it represents more or less $560 million for the second quarter and for the third quarter. We present the dividends we are able to repatriate in our accounts. So in Q2, it was approximately $350 million, and in Q3, it was the Yamal dividends.

Okay. All right, I will push further. Thank you very much.

And the last question is from Biraj Borkhataria with RBC. Please go ahead.

Hi there. Actually, I'm going to push a bit further on Lucas' question. So for the Yamal offtake, can you just confirm whether there's any restrictions on the difference between earnings and cash flow received from that side of the Russian portfolio? I get that within the equity interest of Yamal at a project level there might be some issues on getting the cash out. But for the offtake side, should we assume the earnings flow straight to the group cash flow? And then the second question is just on the LNG portfolio overall. Are you able to disclose what the level of spot sales is or spot sales was in Q3, and what you would expect to have in Q4, as a proportion of the portfolio? Thank you.

So Yamal offtake; I'm not sure to have fully understood your question. But we gave cash received from Russia on our assets. It's cash received from Novatek or cash received for Yamal. And once again, you have the figures for Q2. You have the figures for Q3. In Q2, it represents the Novatek dividend, and Q3 represents the Yamal dividend in Q3, which is approximately $350 million.

Jean-Pierre, I was considering the offtake aspect. As a trading business, you are acquiring oil-linked volumes and selling unhedged LNG. Can we assume that the cash flow generated from this segment of the business is unrestricted regarding its contribution to the group's cash flow statement?

No. There is no sanction. Our duty is to execute the contract. We have some of the contracts. We have to sell part of the Yamal EV volumes to Europe or to Asia. Our customers expect that from us. There are no restrictions.

Okay. Okay. That's very clear.

Regarding our global portfolio, I already mentioned it to you.

No, that's very clear and then the spot LNG sales?

Honestly, I do not have the figure for Q3. My colleagues will come back to you. It should represent something like 2 million or 3 million tons, but then we will come back to you with the precise figure.

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

Thank you. Good morning, Jean-Pierre. I have three questions. First, can you discuss the refinery strike and whether the two refineries are currently operational or completely shut down?

I'm sorry, but the line is very bad, and I was unable to understand your question. Sorry, could you repeat?

Okay. Sure. I'm referring to the refinery in France. I think the labor unit that we start strike on Monday. Can you confirm whether the facilities are currently running or that have been totally shutdown on those two refineries?

What I can tell you is that we have the refinery normally. That was shutdown in October. And we have a second refinery in France that was impacted as well by the strike. More or less two refineries in France were impacted by the strikes in October.

Okay. And can you also tell us whether there's any upstream production contracts with any meaningful expiration in 2023 or 2024?

Honestly, I have nothing in mind because we have some end of contracts that expired last year. I think there are no sizable contracts expiring over the next couple of years, but we are anticipating growth in production.

Okay. Perfect. Thank you.

Thank you.

The next question is from Amy Wong with Credit Suisse. Please go ahead.

HI, good afternoon, Jean-Pierre, a couple of questions from me, please. The first one is on your Casa dos Ventos acquisition in Brazil announced yesterday. What kind of debt levels sit in CDB at the moment? And what kind of CapEx per megawatt should we be expecting for that development pipeline? And then my second question relates to just your capital return policy. I think at the Capital Markets Day, Patrick said that the 35% to 40% cash flow to shareholders had a soft ceiling. What kind of conditions would we have to see to see you guys go beyond that ceiling? Thank you.

Yes. So the capital return policy. Yes, we are very clear on the guidance given by the Board, the information provided to the market at the end of September. Your last point; on delivering above 40%, we will be more than happy to do so. Having said that, the margin needs to be, of course, very high to get to that level, particularly in oil, gas prices, refining margins, petrochemical margins, all our trading business needs to perform particularly well in that time. Regarding the Brazil acquisition, we announced yesterday that we will create a joint venture with Casa dos Ventos, the largest renewable energy developer in Brazil. We will have a stake of 34% in that JV, but having an option to acquire an additional 50%, to reach more or less 50-50 in the coming years in the joint venture. As for CapEx per megawatt, I think it's not very relevant given the fact that we acquired 50% of the portfolio already in production or at early stages, as well as 50% of the portfolio that will come to be developed in the coming years. Our front cash payment was approximately $550 million, which I think is in line with our abilities to have assets that deliver a return on equity above 10%. However, it’s not very relevant to compare with the other portfolios.

Can I ask a quick question? It's great to see that you are providing a one-month salary bonus for all employees. Could you share some details about the total amount of that bonus and whether it has been included in your Q3 figures?

Right. It represents more or less 7% of the global salary cost, but it will be capped. There will be a minimum, but it will be capped at €6,000 per employee. So more or less 7% of the global salary costs worldwide. It will not be in my Q3 numbers; it will be in my Q4 numbers, of course.

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

Yes, Jean-Pierre thank you for the details. Just one quick question left, which is around the lag effect on dividends on equity affiliates that you mentioned. Is that something that is meaningful and we should expect a catch-up in the fourth quarter, maybe beginning of next year? Any details on that would be helpful.

The performance in the third quarter is closely tied to the energy sector, particularly the LNG business. A significant portion of our net income is reported on an equity basis, which means that while the performance impacts your net operating income immediately, we have to wait for dividends to see that reflected in cash flow from operations. The timing of this effect varies based on the country and our partnerships, leading to a delayed impact on cash flow. There is approximately a six-month timeline between the increase in net operating income and its effect on cash flows.

That’s it. Thank you.

The last question is from Kim Fustier with HSBC. Please go ahead.

Hi. Good afternoon. I had two questions, please. The first one is that I was intrigued by your comments that you're not seeing cost inflation in upstream other than that coming from higher energy costs. We're hearing from other companies that were great going up late costs of rising. So I was wondering if you could offer any more color on upstream costs and the broader operating and sanctioning environment in the upstream. My second question is on refining. And specifically, if you could give an update on the Leuna refinery in Germany, that used to be supplied exclusively by Russian pipeline crude. Now that we're a little more than a month away from the start of the EU embargo in December, is the Leuna refinery now able to fully run on non-Russian seaborne crude. Thanks.

No cost inflation. Yes, so I confirm my comment that at present time, given that we are not very present in the US share, we do not see really inflation in our costs. Of course, there could still be some weather difficulties. I have in mind projects presented, six months ago, it was just after the beginning of the war between Ukraine and Russia. At that point, the teams came to us to explain with an impact on the steel price around plus 40%, something like that. So we determined we were not in a position to sanction projects. That’s how we mitigate the cost inflation. We are not in real use, so we have to be patient. We have time to sanction projects. Not all volumes are affected by this. However, at present time, given globally the investments that have been made by all oil and gas companies since 2015 or 2016, we do not see strong inflation. I do not expect strong inflation in our books in the coming months. Regarding Leuna, this refinery was designed to run Russian crude. So we are very clear that this was articulated, it was in March when we published our rule of conduct regarding Russia, that we no longer purchase any spot Russian crude to supply our refineries, and of course, Leuna was the first case for Leuna. Before the crisis, almost 100% of the crude run through Leuna was Russian crude, I think the exact figure is 95%. We had to find alternatives. And so the alternatives will come primarily from Poland. We expect this alternative sourcing to supply the Leuna refinery. It's not easy as we have to find new suppliers. We are engaging in talks with the German authorities to make them aware of these difficulties and concerns. We see at the time that it was possible to import seaborne materials to supply with the Leuna refinery.

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