Ladies and gentlemen, welcome to the Third Quarter 2022 Results Conference Call. At any time during the presentation you may press star one to enter the queue for the question and answer session. 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 Sbraire speaking. We reported solid third quarter results that continue to demonstrate TotalEnergies' ability to successfully leverage the very strong and volatile environment. This success allows us to further strengthen the balance sheet and to share the benefits with our employees and with our shareholders. The third quarter environment was marked by volatility at a very high level. Brent remained strong, averaging more than $100 per barrel in the third quarter and reversed a decline late in the quarter after OPEC+ announced a 2 million bpd quota reduction in early October, which demonstrates that OPEC wants to remain in control despite the risk of lower world economic growth. European gas prices were pushed to the roof by increasing geopolitical tensions and the risk of not enough supply during winter periods, even if this risk is limited as gas storage in Europe are full. As a consequence, NBP nearly doubled in the third quarter to more than $42 per million BTU. A strong driver for the results is our average LNG price, of course. It was lifted by the spike in natural gas prices and reached a record $21.5 per million BTU in the third quarter, an increase of more than 50% quarter-over-quarter. We capture the full benefits of this LNG price thanks to our integrated strategy. European refining margins, EMCV, despite an increase in energy costs, reached $100 per ton in the third quarter, still among the highest we have ever seen, but down from their record-setting second quarter levels, close to $150 per ton. In this context, the company generated third quarter adjusted net income of $9.9 billion or $3.83 per share in the third quarter, in line with the previous quarter. These strong results were achieved despite the increase in taxes. I will tell you more on the U.K. tax in a minute. The decrease in production and oil prices, but mitigated by higher integrated LNG results. Debt adjusted cash flow came in at $12 billion for the third quarter, down 12% from the second quarter, mainly due to lag effect in the dividends received by equity affiliates. Year to date, the FCF is $38 billion, an increase of 80% compared to last year. Cash flow generation of this order of magnitude marks the start of a new era for the company. An era that would be marked in the quarter ahead by a zero net debt balance sheet, an accelerated transition for the multi-energy future, and an upgraded full cycle cash flow payouts for shareholders of 35%-40% from 2022. These were the main messages from the strategy and outlook presentation last month, and the first quarter results confirm these messages. As part of the environment, the effective tax rate for the company increased to 44% in the first quarter from 39% in the second quarter. This is largely due to a higher tax rate for E&P activities as a result of the Energy Profits Levy, $0.6 billion impact on the quarter for four months of taxation. Despite increased taxes, $26 billion paid in aggregate by end of September, mostly in producing countries, our cash flow generation is in any case far stronger than we had projected a year ago, thanks to the favorable price environment. We estimate the impact of the EU solidarity tax at around EUR 1 billion. Operationally, the company's hydrocarbons production was 2.7 million bbl of oil equivalent per day, a 2.5% decrease from the previous quarter, mainly due to plant maintenance, notably at Actis and unplanned downtime at Kashagan, partially offset by the entry into production of Sépia and Atapu, and the ramp-up of Mero -1, all these fields being in Brazil. Year to date, OpEx are traded up to $5.6 per barrel on average. This includes a higher cost of energy, representing $0.25 per barrel. Except these higher energy costs, we do not observe any cost inflation at OpEx level. Cost discipline is a constant priority. We are in a commodity business and maintaining a low break-even is essential to weathering the cycle. Looking at the results segment by segment now. Integrated Gas, Renewables & Power, iGRP. Posted record adjusted net operating income of $3.6 billion this quarter, up $1.1 billion from the second quarter, and cash flow of $2.7 billion, driven by higher LNG prices and strong trading activities in line with previous quarter. The favorable environment allow us to overcome the quarter-to-quarter 10% decrease in LNG sales that's resulted mainly from the Freeport LNG outage and plant maintenance at Ichthys LNG. We expect fourth quarter LNG prices to be above $17 per million BTU, still at high level. I remind you that 70% is linked to Brent formula and 30% to gas spot index. The company continued to execute on its LNG growth strategy by acquiring a stake in North Field South LNG project in Qatar after the North Field East LNG last June. In the electricity business, growth in renewable power generation capacity reached 16 GW at the end of the third quarter, up 4.4 GW over the quarter, including 3.8 GW from the Clearway acquisition and the startup of the Seagreen offshore wind farm in Scotland. We indeed closed the acquisition of 50% of Clearway Energy Group in the U.S. and announced another key acquisition in renewables in Brazil yesterday. It was yesterday. Net electricity production was 8.8 terawatt-hours in the third quarter, up 10% from the second quarter, thanks to the high CCGT utilization rates and growth in renewable power generation. EBITDA from the electricity and renewable business was $160 million in the third quarter, stable compared to the previous quarter. Operating cash flow for iGRP was $4.4 billion in the third quarter, including the positive impact on working capital due to the reduced margin costs and seasonality in the gas and power supply business. The E&P segment generated adjusted net operating income of $4.2 billion and cash flow of $6.4 billion in the third quarter, down about $0.5 billion and $1 billion respectively from the second quarter because of lower production. Quarter to quarter, our average realized liquid price fell by almost $10 per barrel, but our average realized gas price increased by around $6 per million BTU. We are ramping up activities in E&P, notably 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, and a significant gas discovery in Cyprus. The combined downstream segment generated $2.4 billion of adjusted net income and $2.9 billion of cash flow in the third quarter, an outstanding performance even if decreased compared to the record-setting second quarter, thanks to strong distillate margin and a good trading performance comparable to previous quarter. To put this into perspective, over the first nine months, the downstream generated $8.4 billion of cash flow, twice the level of the same period last year, and more than enough to cover the entire regular dividend for the year. Our expectation is that refining margins should remain strong, particularly for distillates, given the ban on imports of Russian petroleum products into Europe effective February 2023. At the company level, over the first nine months of 2022, we generated operating cash flows before working cap changes of around $37 billion, an increase of 85% over the same period last year. Year to date net investments of $12.5 billion are in line with our guidance of $16 billion for the year, including $4 billion in decarbonized energies. We bought back $5 billion of our shares over the first nine months and plan to buy back another $2 billion in the first quarter. Our gearing ratio is down to 4% at the end of the third quarter. Given our solid financial position and the strong cash flow generation, the company is expecting a balanced value-sharing policy that includes an exceptional bonus of one month salary to all our worldwide employees and a new shareholder return policy announced in September that targets 35%-40% cash flow payouts. In addition to the regular third interim dividend of 0.69 EUR per share, which represents a 5% increase from a year ago, the board decided to set the ex-dividend and payment dates for the interim special dividend of 1 EUR per share in December 2022. That concludes my comments, my remarks, and now we can go to the Q&A. Ladies and gentlemen, if you wish to ask a question, please press star one on your telephone keypad. That's star one. The first question is from Irene Himona with Société Générale. Please go ahead. Thank you very much. Good afternoon, Jean-Pierre. I had two questions, please. Firstly, you've had quite a substantial $7 billion working capital release in the third quarter. I wonder if you can talk about the main components and then what could we, if we could anticipate something for Q4, any guidance would be very useful. Secondly, on the Russian impairments you took this quarter, can you please remind us what remains as the net book value after these impairments? Since the strategy you presented last month has left out everything to do with Russia, will you over time just write off whatever remains on the balance sheet, please? Thank you. Okay. Thank you, Irene. Good afternoon. Yes. The first question regarding working cap. That's true. We reported $6.7 billion working cap released in the third quarter, and there is four, I would say, or three main factors behind this performance. The first one, for obvious reasons, we have working capital released in relation with the price effect on stocks of around $3 billion representing + $3 billion, more or less. We have a $2.4 billion working capital released as well linked to variation margin release for our gas and electricity business. Thanks to several optimization and exposure reduction actions. We have as well a $2.1 billion working capital release in relation with our E&P tax payable. It's mainly the case in North Sea countries, so Norway and U.K. mainly. On the other side, we have a -$0.8 billion of various effects on payables and receivables balance. That was the main driver behind this performance. For the fourth quarter, of course it will depend, it will highly be dependent on the evolution of the prices for the valuation of stocks and for the gas and electricity variation margins. I have in mind that most of the tax will not be paid in 2022. It will be paid rather during the first quarter 2023. I do not anticipate a cash out, a stronger cash out or reversal of this performance in the fourth quarter according to the current environment. Now perhaps your question on impairments. Yes. We were recording in our accounts a new and additional write off on the value of our Novatek shares for $3.1 billion in the fourth quarter. Because of course, we have to review the cash flow long-term scenarios to include in fact greater uncertainties on cash transfer from Russia. That was the main driver behind this impairment. The appendix on Russia, at that time we gave the capital employed in Russia, close to a $14 billion end of last year. Now given all the different impairments we made, we made, I remind you, $4.1 billion impairment in the first quarter, mainly on Arctic LNG 2. We made three or 3.5 billion impairment in Q2, mainly on Novatek share value, and this quarter an additional 3.1. All in all, it represent more or less impairment of $11 million. Now to answer to that, to your question, in our accounts, we have capital employed for Russia around $6 billion, taken after all this impairment that has been done. 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 of 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 fact that there were quite a few shutdowns. I was wondering if perhaps you could give us some visibility of when you expect some of this production to come back, especially Freeport LNG, Nigeria LNG, and Ichthys LNG returning back from scheduled maintenance. 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 three. 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 Donges refinery. I was wondering if you could give a bit more visibility on that. Thank you. Yes. So perhaps I will start with the second question. So, it'll be very clear. The increase regarding Scope 1 and 2 in Europe is 100% linked to the CCGT. I remind you that in 2015 we do not have any CCGT in our portfolio. Now we have different CCGT, so in France, in Spain, in Belgium. By the way, we have started a new CCGT in France, in Brittany, in Landivisiau, beginning of this year. Given that, for obvious reason, the CCGT performed particularly well during the third quarter, that's the driver behind this increase regarding Scope 1 and 2 in Europe. Your second question regarding our LNG strong results despite shutdowns. For me, it's the demonstration that the success of our integrated strategy on LNG because we were able to replicate very good and very high performance for this LNG business despite shutdowns, despite the loss of Freeport cargoes in particular in the third quarter. According to the information I have, Freeport is supposed to come back to 100% capacity in December this year. Nigeria, it will probably be next year. Ichthys, so the shutdown has been completed, and so it's supposed to come back to normal production in the fourth quarter. Thank you. The next question is from Martijn Rats with Morgan Stanley. Please go ahead. Hi. Hello. I've got two questions, if I may. First of all, I wanted to ask if you could say a few words about the impact of the refinery strikes in France during the quarter, and say a few words on how that might impact fourth quarter results. I heard you comment on distillate yields, or sorry, distillate cracks, and that they may continue to be supported as a result of the EU import embargo on Russian oil. This remains a very hard to navigate issue, and I was wondering if you could set out more broadly what you think the impact will be of the EU embargo on Russian oil, both for crude and for product over the next couple of months. Okay. The impact on the refinery strikes in France, well, it's very, it would be a very theoretical calculation, because of course on one side we lost production in France coming from these refineries. We benefited for increased margin in our refineries in Belgium, in particular or in Germany. I will not give you a very precise figure. It's very limited, the impact of the strikes in France over the October month. Okay. Distillate cracks, yes. They are strong. We think that of course the ban on Russian petroleum products that will be effective in February 2023 will contribute of course to maintain this distillate cracks at very high level. It will not be so easy for Europe to compensate the loss of these volumes. That's why we think that once again the margin could remain at high level. For crude it's probably a bit easier to compensate the loss of the ban on Russian crude that will be effective in December because you can of course reroute crude from other countries. We are very clear that all these bans will contribute to support the prices, because of course, Russian crude will need to find alternative customers, so it will be India, it will be perhaps in China or more globally in Asia. These countries could benefit from discounted crude. On the opposite, the European refiners will have to pay premium to attract new crudes. That's the paradox of this ban I think implemented at the level of the EU. Okay. Wonderful. Thank you. The next question is from Christopher Kuplent with Bank of America. Please go ahead. Oh, 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 premature or too early, I think, to give a view. In chemicals, we start 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 station, we do not see any drop in volume. We see outlook for next year. For sure, recession should have an impact on chemicals, should have an impact on gas demand as well. Too early, I think, to give precise figures. Fair enough. Thank you very much. The next question is from Oswald Clint with Bernstein. Please go ahead. Yes, Jean-Pierre, thank you. Just back on the LNG side, please. I wonder if you could help us just, you know, understand a little bit more about how you're doing so well. I mean, obviously, some huge gas price differentials in the quarter, especially around quarter end, which need to be marked to market. But you're also buying. I think you're actively buying spot LNG cargoes in the quarter. So was it? Is it the case that you know, are having some losses on hedge deliveries, but offsetting it with new spot cargoes, and were able to offset that through the profit on those? Is that something that's going on? Secondly, I mean, I understand the confidentiality around assets in Qatar, but is there anything you can say around what we might expect, perhaps proportional EBITDA uplift from starting up what is, I think, one of the largest solar plants in the world that you started up this month? As we look into next year, is this gonna be something material? Thank you. Our performance regarding LNG. I think 2021 definitely marked the start of a new era of performance for this LNG and electricity trading. This business segment, quarter after quarter, replicates very strong performance. Of course, we do not give full details, absolute value for our trading business. I can tell you that we, in the first quarter, replicate on the LNG gas and power trading the excellent performance of Q2 2022. In Q2 2022, we replicate the high performance we have in the first quarter of 2021. perhaps you remember that in the first quarter of 2022, we announced that we have a very high trading performance. We qualified this performance as outstanding performance of more than $500 million. Having said that's true that we have to record in the Q3 results the impact of the Freeport outage and the loss of cargos and the fact that, of course, we have to offset hedging losses. Being able to replicate quarter after quarter a very good level of performance demonstrate that we are able, given the global portfolio we have, to offset in fact this hedging losses. We have a worldwide presence, so we have LNG production in almost all of the main hubs. In the US, or in Qatar, in Australia, just to mention. Of course, we have the LNG coming from Russia as well. We have, given this portfolio and given the outlet we have, so we manage between sources and outlets. It's the way our trading is able to deliver, once again, quarter after quarter, very good performance. Qatar, yes. The solar farm was inaugurated, it was last week, I think. In Qatar. It's globally one of the most sizable solar farm worldwide. I think the equivalent of representing 800 MW. I do not have, to be honest, the EBITDA, but I will ask my team, and so they can come to you with the figures. Very clear. Thank you. The next question is from Lydia Rainforth with Barclays. Please go ahead. Thank you. Jean-Pierre, good afternoon. Good afternoon. Two questions if I could. The first one, with the strategy presentation, I think the guidance was for gearing to year-end to be at 5%, and effectively you're already there at the end of this quarter. I appreciate that's the release of working capital and the right answer, but is there an update as to where you think you'll be at year-end, in terms of the gearing number? Then secondly, just bigger picture question, in terms of renewables and the low carbon side, we are clearly seeing higher interest rates, more difficulty accessing finance, greater desire for energy security. Do you think that starts to change the structure of some of the renewables businesses, gives an advantage to companies such as TotalEnergies? Thanks. Yes. That's true that our gearing is already below 5%. With a net debt at $5 billion. But it's difficult, you know that we do not have any magic figure in terms of our target, and we will, as a CFO, I will be more than happy to continue to strengthen my balance sheets and to continue to decrease the gearing. Having said that, in the first quarter, given the assuming that we will continue to generate more or less the same level of cash flow from ops, given the target we have for CapEx at $16 billion globally for the full year, taking into account that we will continue our buyback program at $2 billion. That we will pay the special dividends representing more or less $2.5 billion. I would say that we should remain more or less in the same ballpark, around 4% or below 5%. Of course, it will depend on the, once again, on the working capital, but I already mentioned that I do not anticipate as well very strong variation for the working cap as well. I would say more or less at the same level as the level we had end of September. For renewable, in fact, for sure, in that sector it's not necessarily the same in the upstream sector. We have to face inflation and to face higher interest rates. In fact, this additional cost, so both inflation and higher interest rate will be passed in fact to the final customers when we negotiate the contract to sell the electrons. Because as you know, we target for this type of project a double-digit profitability. When we sanction the project, we have the clear view on the CapEx, and so we lock in the CapEx at that time, not to be exposed anymore to the future inflation. We have a clear visibility on the leverage, on the cost of financing, and we adjust in fact the level of PPA we are ready to sign, to dare to be in a position to deliver the targeted double-digit profitability. There is no miracle I would say with this interest rates increase or this inflation will not change the threshold or will not change the methodology we use to sanction projects. On the opposite, I would say that it could have some positive effect for TotalEnergies, because of course it will clean, I would say, the competition with less companies able to enter or to continue development in that field. Great. Thank you very much. We have the strong biology, less competition, so it will be profitable for us and positive for us. The next question is from Bertrand Hodee with Kepler Cheuvreux. 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 regas capacity that you have secured, that you are able in fact to maximize your LNG spot selling price? Or is there other reason for that outstanding performance? For sure, having made the acquisition of the Engie LNG portfolio, I think it was three or four years ago. It gives us now access to 18 million tons of regas capacity in Europe. It means that we have more or less 16% of the global regas capacity in Europe, so it's a huge advantage for our traders to play, in fact, the arbitrage between the U.S. and Europe. For sure, it's key in this LNG trading performance. Once again, having a production contract on the main hubs, I remind you that we are number one LNG exporter in the U.S. as well. We have a strong presence in the U.S., strong access to U.S. with more than 10 million tons of LNG coming from the U.S. This has the capacity through our ships to deliver this LNG to our European customers thanks to this regas capacity. Of course, we have on top of that other sources of LNG in Asia, in the Middle East, and customers in Asia. All in all, it allow our traders to arbitrage between the different markets. Now, given the price of the LNG, each cargo, it represents something like $80 million, even $100 million for each cargo. When you are able to reroute or to arbitrage between the different markets, of course it's a very efficient way to maximize and to maximize the value coming from that business. Many thanks, Jean-Pierre. The next question is from Alastair Syme with Citi. Please go ahead. Hi, Jean-Pierre. This EU solidarity tax, you mentioned the EUR 1 billion figure, but, you know, is this still an estimate? 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. Yeah. Secondly, you know, the last few weeks we've seen a bit of a collapse in spot gas prices in Europe. You know, 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? Okay. The EU solidarity contribution. As you know, we will be impacted by this EU solidarity contribution in six countries in Europe. It will be France, Germany, Belgium, Luxembourg, so mainly on our refining activities. Plus Denmark and the Netherlands on the E&P activities. At present time, there is a lot of uncertainties regarding the implementation of this tax, because as you know, the EU, I would say, gave a framework for this solidarity contribution, and each countries is supposed to adjust or to adapt this frame locally to their own requests. Having said that, we made a lot. Because there are uncertainties regarding the rate. The rate that would be used because the EU just gave minimum tax rates. Uncertainties regarding the use of carry loss forward. By the way, another uncertainty regarding the fact that the basis if it would be 2022 or 2023, because in the text you have 2022 or 2023. Having said that, we're engineers, so we made a lot of different calculations with different scenarios. All in all, we the conclusion that this EU solidarity tax should represent something like EUR 1 billion for the full year 2022. The EU gas price falling. Yes, for sure. At present time we see NBP around $20 per million BTU. It was above $50 per million BTU. It was end of August, I think. So it's a huge drop. In fact that $20 per million BTU is not ridiculous when you compare the level we had before the crisis. The main factor explaining this drop that you know better than I do, so it's of course lower demand in Europe due to the temperature, so high temperature that we have at present time. The lower heating needs of course in relation with this situation. the gas stocks that are almost full, they are full in France, and so they have been replenished over the past months. A strong competition between EU companies and Chinese companies to attract LNG cargos to Europe. That created condition. On top of that, you have the U.K. situation with little storage capacity in the U.K. That creates another subject in fact to evacuate the gas coming to the U.K. to other European countries. Having said that, the price will be highly dependent on the temperature of course, and the final consumption in Europe. Stocks are full, so we anticipate that winter 2022 should not be a big concern for EU. You will have to rebuild the stocks for the winter 2023. Given the lack, once again, of gas capacity of Europe to completely compensate the possible fall in Russian gas coming through pipelines, it should be highly supportive to gas prices in Europe at that time. That's why we short term, I don't know. It's a matter once again of volatility, temperature, consumption and so on. Middle term, it's the message we convey in New York when we presented our outlook. We are very supportive, particularly for LNG gas in Europe for these intrinsic reasons. The need for Europe to attract LNG cargos to compensate the lack or the loss of pipeline gas, Russian gas. Can I just clarify on the solidarity tax, the EUR 1 billion estimate? Does that include the tax loss carry forward, or is that a gross number before you would ask? It depends. We made some calculations depending on our anticipation of what the law could be, depending on the countries. Okay. It's not necessarily a big impact. It depends on the country, it depends on the situation. Okay, thank you. The next question is from Lucas Herrmann with Exane. Please go ahead. Yeah, thanks very much. Good afternoon, J.P. A couple as well, and maybe some points of clarification on windfall taxes as well. I just wanted to go back to, you know, LNG and get some better sense of what the hedging policy is now and the extent to which, you know, the LNG in the portfolio is exposed. Because one of the things I think Patrick made quite clear in New York was that there is uncertainty as to, you know, the longevity of the contracts with or whether there's sanctioning of the Russian contracts, which, you know, for you is an offtake, I think 5 million tons per annum. As a consequence, there seem to be a reluctance to actually hedge those volumes. Can you give us some idea as to the extent to which the length in your portfolio, the uncovered portion of the LNG trading portfolio, has you know increased over the course of you know the last few months or will increase going into the fourth quarter, and therefore you are more exposed to you know volatility and spot pricing? That was the first question. The second, just staying with that, can you give us any indication of the cash flows that you derive from trading Russian LNG? Or is that just seen as being you know too difficult to predict as you've said previously, and therefore won't be disclosed as part of your disclosure of cash flow from Russia. You've clearly taken those cash flows out when you present your strategic view going forward five years, but they very clearly remain in when you present data today. Then, sorry, just going back to Alastair's, I'm sorry for the long list. Just to be clear, the windfall tax that you're referring to, or the estimate of EUR 1 billion, is that prorated from when those taxes become applicable? I ask because it's considerably more modest than the number that you indicated, again, at the strategy day when including the- No U.K. component, you talked to something near to 2.5 billion. No. Okay, perhaps I will clarify this subject first. We have two different subjects. It's windfall tax profits in the U.K. It's already implemented. With the vote on the implementation in July, retrospective to end of May, and we mentioned in New York that assuming a $30-$35 per million BTU NBP over the first quarter, it should represent for 2022, from end of May to end of December, more or less $1 billion or EUR 1 billion. Okay? Yeah. It's for the windfall tax profit in the U.K. It's implemented, so there is no doubt. In fact, the only uncertainty is the NBP level and the production on which this tax will be applicable. EUR 1 billion more or less for this subject. Excellent. End of September, given that we have to record over the third quarter, in fact more than four months of windfall tax profits in the U.K, the impact is something like $640 million. Okay? The second subject is EU solidarity tax. So at present time we have nothing in our accounts because once again, there are a lot of uncertainty regarding the way this tax will be implemented. The figure I mentioned is for this solidarity tax. So EUR 1 billion or $1 billion, we gave exactly the same figure in New York. I remember well because I gave that figure. Okay. There, of course, there are some discussions or uncertainty regarding when the tax will be payable. Once again, the methodology, but it's supposed to be a one-off. That's the main difference compared to the U.K. windfall tax. That it's supposed to be applicable since until 2023. 2025, sorry. Okay? Great. Thank you. Regarding LNG hedging policy, our policy is to hedge the following 12 months. That's what we mentioned already to you many times. That, with some exceptions, what has been mentioned regarding our Russian assets is that we do no longer hedge Russian volumes since February 2022 to take into account the uncertainty you mentioned regarding the access to the volumes. That's our policy. A global policy, but with an exception on Russia. Okay. 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. Am I to take it that 6 million tons of LNG coming from Yamal at the present time is unhedged? Yes. More or less, because we hedge only the two first months of 2022. The calculation is correct. In 2023 it will be something like 5 million tons of sales coming from Russia. Okay. Which will stay unhedged. Can you give us any indication, J.P., sorry to ask, in terms of the contribution- No. What we gave very transparently since once again the publication of the risk assessment documents is the cash that our Russian upstream activity are able to generate. You will see that in the Q2 or Q3, it represents more or less $550 million, so for the second quarter, for the third quarter. It represent the dividends we are able to repatriate in our accounts. In the Q2 it was Novatek dividends. In the Q3 it was Yamal dividends. Okay. All right. I won't push further. Thank you very much. Thank you. The next question is from Biraj Borkhataria with RBC. Please go ahead. Hi there. I actually, I'm gonna push a bit further on Lucas's question. 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 the 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? 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. Yamal offtake. I'm not sure to have fully understood your question. That's what we gave. The cash we received from Russia on our assets, so it's cash received from Novatek or cash received for Yamal. Once again, you have the figure for the Q2, you have the figure for the Q3. I gave the indication that Q2 to represent Novatek dividend and Q3 to represent Yamal dividend. It's $350 million for Q2 and $350 million, more or less the same figure for Q3. Jean-Pierre Sbraire, I was thinking more the offtake side. You as a TotalEnergies trading business are buying, you know, oil-linked volumes and selling unhedged LNG. Mm-hmm. Is it fair to assume that cash flow that you generate from that part of the business is there's no restriction on where the cash resides in terms of, you know, goes straight to the group cash flow statement? No, there is no sanction. There is no sanction on the- Okay. That's clear. Thank you. Our duty is to execute the contracts we have. The contract we have to sell part of the Yamal LNG volumes to Europe or to Asia. It's, by the way, what the European authorities are waiting for us. No, there is no restrictions. Okay. Perfect. That's very clear. It's part of our global portfolio, the global optimization I already mentioned to you. No, that's very clear. The spot LNG sales? Honestly, I do not have the figure for the Q3. My colleague will come back to you. It should represent something like 2 million or 3 million tons. They will come back to you with the precise figure. Thank you very much. Thank you. The next question is from Paul Cheng with Scotiabank. Please go ahead. Thank you. Good morning, Jean-Pierre. Two questions. One, can you talk about the refinery strike? Like, I think that they just restarted on Monday for two of your refineries in France. Can you confirm whether those two refineries right now are shut down or that you still be able to run? That's the first question. I'm sorry, Paul, but the line is very bad, and I was unable to to understand your question. Sorry. Could you repeat? Sure. I'm referring to the recent refinery strike in France. I think the labor union that will restart the strike on Monday. Can you confirm whether the facilities are currently running or that has been totally shut down on those two refineries? I can tell you that we have a refinery in Normandy that was shut down almost all October month. We have a second refinery in Feyzin, south of Lyon, that was impacted as well by the strike. More or less, for October, it's two refineries in France that were impacted by the strikes. Okay. Can you also tell us that whether there's any upstream production contract, any meaningful expiration for 2023 or 2024? Sorry, I haven't understood. It's about the upstream contracts, but what is your question on these contracts? Yeah. Any meaningful upstream production contract will expire in 2023 or 2024? Like if we can- You mean. in that type of one gap contract the development contracts? No. Production contract. Like you have Total one contract, Total gas, one contract expire early this year. I just want to know if there's any other meaningful production contracts in your portfolio will be expired- What do you mean by the production contracts? A PSC? Your operating contract. Honestly, I have nothing in mind because we have the end of the non-renewable or the Qatargas 1 contract. It was end of last year. We have the same on Bongkot in Thailand. We draw from Myanmar, just to remind you the main contract that were ended very recently. On top of that, in the current month, I do not think it will be. I have nothing in mind or nothing sizable in mind. No. Okay. Will do. Thank you. By the way, the production is supposed to grow over the next couple of years. 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 sits in CDV 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%-40% cash flow to shareholders had a soft ceiling. What, you know, what kind of conditions would we have to see to see you guys go beyond that ceiling? Thank you. Yes. The capital return policy, yes, we are very clear. It is the guidance given by the boards that the information or the guidance we gave to the market end of September. The condition, having said that, you're right that Patrick Pouyanné mentioned that the 40% is not a limit. The 35%-40% is the guidance, but there is no limit, in fact, and the 40% is not a ceiling. What could convince us to go beyond that, of course, is if the environment is very, very high level. If you have at the same time oil, gas prices, refining margins, petrochem, all our business, LNG trading performing particularly well. That's what I can tell you. On the Brazilian acquisition, we announced yesterday, so it's the fact that we will create a joint venture with Casa dos Ventos, so in Brazil, it's 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%. That to be more or less 50/50 in the coming years in that JV. The CapEx per megawatt, I think, is not very relevant, given the fact that we acquired 50% of the portfolio already in production or at early stage, but also 50% of the portfolio that will be developed in the coming years. All in all, we pay an upfront cash payment of $550 million. I think it's perfectly in line with our objective to have assets able to deliver return on equity above 10%. Once again, the comparison with the other portfolio, I think in that case is not very relevant. Okay. Could I squeeze in a quick one? It's nice to see that you guys are putting in a 1-month salary bonus for all employees. Could you just comment, I mean, give me just an idea of what size the total amount of that is and if it's been accrued in your 3Q numbers? Well, it will present more or less 7% of the global salary cost. But it will be capped. There will be a minimum, but it will be capped as well to EUR 6,000 per employee. So more or less 7% of the salary costs worldwide. Great. Thank you very much. It will be. It's not in my Q3 numbers. It will be in my Q4 numbers, of course. Okay. Gotcha. Great. The next question is from Henri Patricot with UBS. Please go ahead. Yes, hello Jean-Pierre. Thank you for your data. Just one quick question left, which is around the lag effect on dividends from 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. Thank you. It's obvious that the performance in the Q3 is particularly linked to the performance in the LNG sector. The LNG business is in the majority of the cases accounted on an equity basis. That means that of course you have on your net operating income the immediate effect of the performance. In cash flow generated from operations, of course, you have to wait for the dividends. There are some rules depending on the country, depending on the partnerships. It's like you do not have an immediate effect on your cash flow FFO. There is a timeline effect between the increase of impact on the net operating income and the impact you will have on the cash flow from it. I cannot answer to you. It depends on the geography, it depends on the business. It's a timeline between, I would say, around six months, something like that. It depends, because on some geographies you are able to put in place interim dividends to accelerate, in fact, the cash out from the businesses. In some of our geographies, you have to wait, because there is just one dividend per year. It's a mix between the different situations. 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 comment that you're not seeing cost inflation in upstream other than that coming from higher energy costs. We're hearing from, you know, from other companies that rates are going up, labor costs are rising. 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. I confirm my comment that at present time, given that we are not very present in the U.S. shale, we do not see really inflation in our costs. Of course, still, there were difficulties. I have in mind a project that was presented, I think it was six months ago. It was just after the beginning of the war between Ukraine and Russia. At that time, the teams came to the ExCom asking us to sanction the project with an impact on the steel price around +40%, something like that. At that time we said then, "No, we are not in a hurry to sanction project." It's the way we mitigate in fact this cost inflation. If in some projects we have to face this situation, we are not in a hurry, so we have to be patient. We have time in fact to sanction project. It's not volume over value. Obviously at present time, given globally the under investment that has been done by all the oil and gas companies since 2015 or 2016, globally, we do not see a strong inflation. We do not anticipate strong inflation in our books in the coming months. Russia, Leuna. Yes, Leuna was designed in fact to run Russian crude. As you know, we were very clear, it was very early in the year, it was in March when we published our rule of conduct regarding Russia, that we no longer buy any spot Russian crude to supply our refineries. Of course, Leuna, it was still the case for Leuna. Before the crisis, almost 100% of the crude run in Leuna was Russian crude. I think the right figure is 95%, so 95%. We have to find alternatives. The alternatives will come from a pipe coming from Poland, in fact. We have to import seaborne crudes to compensate the lack or the loss of Russian crude. I will not tell you that it's easy. We are very clear. We have of course discussions with the German authorities to make them aware of these difficulties of this country. We see. At the time, it was feasible to have more or less 800 kilotons of oil per this pipe coming from Poland. We'll see in the near future if we continue with this alternative source to supply Leuna refinery. Okay. I think it was the last question. Okay. Thank you very much for your time. I will give you a rendezvous I think now it will be in February for the 2022 results. Thank you again. Bye-bye. Ladies and gentlemen, this concludes the conference call. Thank you all for your participation. You may now disconnect.