TotalEnergies SE Ordinary Shares

Ladies and gentlemen, welcome to the third quarter 2022 results conference call. At any time during the presentation, you may press star and one to enter the queue for the question and answer session. I now hand over to Jean-Pierre Vraire, 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 continue to demonstrate Total Energy's ability to successfully leverage the very strong and volatile environment. This success allows us to further strengthen the balance sheets 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. Brands remained strong, averaging more than 100 dollar per barrel in the third quarter, and reversed a decline late in the quarter after OPEC Plus announced a 2 million per barrel quota reduction in early October, which demonstrates that OPECs want 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 of not enough supply during winter periods, even if this risk is limited as gas storages 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 in the third quarter, an increase of more than 50% quarter to quarter. We captured the full benefits of this LNG price thanks to our integrated strategy. European Refining Margins, MCV, despite an increase in energy costs, reached $100 per tonne in the third quarter, still among the highest we have ever seen, but down for their record-setting second quarter levels, close to $150. 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 UK tax in a minute. And 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 first quarter, down 12% from the second quarter. mainly due to a lag effect in the dividends received by equity affiliates. Year-to-date, the STF 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 area for the company, an area that would be marked in the quarter head by a zero net debt balance sheet an accelerated transition for the multi-energy future, and an upgraded through-cycle cash flow payouts for shareholders of 35% to 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 of 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 EMP activities as a result of the Yuki Energy profit levy, $0.6 billion impact on the quarter for four months of taxation. Despite increased taxes, $26 billion paid in aggregates 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 1 billion euros. Operationally, the company's hydrocarbons production was 2.7 million barrels per day, a 2.5% decrease from the previous quarter, mainly due to planned maintenance, notably at Ictis, and unplanned downtime at Cachagan, partially offset by the entry into production of Sepia and Atapu, and the ramp-up of Meruan, all this field being in Brazil. Year-to-date, OPEX are trending up to $5.6 per barrel on average. This includes higher costs 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, renewable and 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 energy prices and strong trading activities, in line with previous quotas. The favorable environment allows us to overcome the quarter-to-quarter 10% decrease in LNG sales that resulted mainly from the Freeport LNG OTH and planned maintenance at ICTIS 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 Northfield South LNG project in Qatar after the Northfield East LNG last June. In the electricity business, gross renewable power generation capacity reached 16 gigawatts at the end of the third quarter, up 4.4 gigawatts over the quarter, including 3.8 gigawatts from the Clearway acquisition and the startup of the Sea Green Offshore Wind Farm in Scotland. We indeed closed the acquisition of 50% of Clearway Energy in the U.S. and announced another key acquisition in renewable in Brazil yesterday. It was yesterday. Net electricity production was 8.8 TWh in the first 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 IDRP was $4.4 billion in the first quarter, including the positive impact on working capital due to the reduced margin costs and seasonality in the gas and power supply business. The EMP 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 to 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 startup of production at the ITK field in Nigeria, the launch of the Begonia project in Angola and the Phoenix project in Argentina, and a significant gas discovery in Cyprus. The combined downstream segments 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 23. At the company level, over the first nine months of 22, we generated operating cash flows before working cap changes occurred. 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 energy. We bought back $5 billion of our shares over the first nine months and plan to buy back another $2 billion in the fourth quarter. Our dealing rate ratio is down to 4% at the end of the third quarter. Given our solid financial position and a 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 interest dividend of €0.69 per share, which represents a 5% increase from a year ago, the Board decided to set the ex-dividends and payment dates for the interim special dividends of 1 euro 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 1 on your telephone keypad. That's star 1. The first question is from Irene Jimona with Societe Generale. 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. And secondly, on the Russian impairments you took this quarter. Can you please remind us what remains as the net book value after these impairments? And since the strategy you presented last month has left out everything to do with Russia, will you, over time, just write off whatever remains from the balance sheet, please?

Thank you. Okay. Thank you, Oren. Good afternoon. Yes, so the first question regarding working cap. So that's true. We reported a $6.7 billion working cap released in the first quarter, and there is four, I would say, or three main factors behind this performance. So the first one, for obvious reasons, was working capital released in relation with the price effect on stocks of around $3 billion, representing plus $3 billion, more or less. We have a $2.4 billion working cat release 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 cap release in relation with our E&P tax payable. It's mainly the case in North Sea countries, so Norway and UK mainly. And on the other side, we have a minus $0.8 billion of various effects on payables and repayable balance. So that was the main driver behind this performance. So for the first quarter, of course, it will highly be dependent on the evolution of the prices for the valuation of stocks and for the gas and electricity variation margins. But 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. So I do not anticipate a strong cash-out or reversal of this performance in the fourth quarter, according to the current environment. So now perhaps a question on impairments. Yes, so we were recording in our account a new, an additional write-off on the value of our novelty shares for $3.1 billion in the third 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. So that was the main driver behind this internment.

So we are very... ...of last year, so...

And now, given all the different impairments we made, so we made, I remind you, 4.1 billion impairments in the first quarter, mainly on Arctic 2. We made 3.5 billion impairments in Q2, mainly on Novatec short value, and this semester, this quarter, sorry, an additional 3.1. So all in all, it represents more or less impairment of $11 million. So now, to answer to your question, in our accounts, we have capital unemployed 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. And I was wondering if perhaps you could give us some visibility of when you expect some of this production to come back, especially... Freeport, Nigeria LNG, and ICSIS 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 three. But there was a 10% increase in scope one and two emissions. My understanding is most of it comes from Europe and the ramp up of CCGTs and the don't refine it. But 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 is very clear. So the increase regarding scope 1 and 2 in Europe is at least a cent linked to the CCGT. So I remind you that in 2015, we do not have any CCGT in our portfolio. So now we have different CCGTs, so in France, in Spain, in Belgium. By the way, we have started a new CCGT increase in Brittany, in the beginning of this year. And given that, for obvious reasons, 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. So 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 on this segment, on this LNG business despite shutdowns, so despite the loss of Freeport cargoes in particular in the first quarter. So, according to the information I have, Freeport is supposed to come back to 100% capacity before November 2020. Sorry? In December this year. Nigeria, it will be probably next year, and it is, 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 Martin Ratz with Morgan Stanley. Please go ahead.

Yeah, hi, hello. I've got two questions over me. 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 four-quarter results. And then also, I heard you comment on distal deals, sorry, distal 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 – which 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. So, the impact on the refinery strikes in France, it would be a very theoretical calculation, because, of course, on one side, we lost... production in France coming from this refined oil, but we benefited for increased margin in our refined oil in Belgium, in particular, or in Germany. So, I will not give you a very precise figure, so it's very, very limited, the impact of the swipes in France over the October month. Distilled quacks, 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 these distilled quacks at very high levels. It will not be so easy for Europe to compensate the loss of these volumes. So that's why... We think that, once again, the margin could remain at a high level. For crude, it's probably a bit easier to compensate the loss of the ban on crude, on traditional crude that will be effective in December, because you can, of course, reroute crude from overseas. from other countries, but we are very clear that all these bands will contribute to support the prices because, of course, Russian crude will need to find alternative customers, so it will be in India, it will be perhaps in China, but more globally in Asia, so these countries could benefit from discounted crude, but on the opposite, the European refineries will have to pay premium to attract new quotes. So 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 Copeland 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 premature, it's too early, I think, to give a figure. So in chemicals, we start seeing that nominally the impact of the possible recession that will... would happen next year. On ourselves, at present time, honestly, given the discounts we have in our retail session, we do not see any drop in volume. So we'll see. I'll look for next year. For sure, the session should have an impact on this, on chemical, should have an impact on gas demand as well. But too early, I think, to give a precise figure.

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, there's 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 active buying spot LNG cargos in the quarter. So is it the case that you are having some losses on hedge deliveries, but offsetting it with new spot cargos and being able to offset that through the profit on those? Is that something that's going on? And then 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? So as we look into next year, is this going to be something material? Thank you.

Okay, so our performance regarding energy.

I think 2021 definitely marked the start of a new reality performance for this energy and electricity trading. And so this business segment, quarter after quarter, replicates very strong, very strong performance. So, of course, we do not give full details, absolute value for our trading business. But I can tell you that we, in the first quarter, we replicated the LNG GAN and power training, replicated the excellent performance of the Q2 2022. In Q2 2022, we replicate the high performance we have in the fourth quarter of 2021. And perhaps you remember that in the first quarter of 2022, we announced that we have a very, very high trading performance. And so we qualified this performance as another performance of more than $500 million. So having said that, That's true that we have to record in the Q3 results, so the impact of the three-port outage and the loss of cargoes and the fact that, of course, we have to offset edging losses, but being able to replicate quarter after quarter, a very good level of performance demonstrates that we are able, given the global portfolio we have, to offset, in fact, these hedging losses. And so we have the worldwide presence, we have the energy production in almost all the main hubs, so in the US, in Qatar, in Australia, just to mention, and of course we have the The energy coming from Russia as well. And so we have, given this portfolio and given the outlet we have, so we manage between sources and outlets. And so it's the way our trading is able to deliver, once again, quarter after quarter, very, very good performance. Qatar, yes, so the solar farm was inaugurated last week, I think, so in Qatar. So it's globally one of the most sizable solar farms worldwide, I think, the equivalent of representing 800 megawatts. 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, Javier. Good afternoon. Good afternoon. 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. And I appreciate the release of working capital and the write-downs, but is there an update as to where you think you'll be at year-end in terms of the gearing number? And then secondly, just a bigger picture question, in terms of renewables and the low-carbon side, we are seeing higher interest rates, more difficulty accessing finance, greater desire for energy security. Do you think that starts to change the structure of the renewable businesses? Is there an advantage to companies such as Texel Energies?

Thanks. Yes, so that's true that our bearing is already below 5%. with the net debt at $5 billion. It's difficult. You know that we do not have any magic figure in terms of target, and so 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, 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 buy-back program at $2 billion, that we will 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 4% or below 5%. Of course, it will depend, once again, on the working capital, but I already mentioned that I do not anticipate as well a very strong variation for the working capital as well. So I would say more or less at the same level as the level we had end of September. So, 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. But, in fact, these additional costs, so both inflation and higher interest rates, will be passed, in fact, to the final customers. when we negotiate the PPA, when we negotiate the contract to sell the electrons. Because, as you know, we target for this type of project a double-digit profitability, so when we sanction the project, we have a clear view on the capex, and so we lock in the capex at that time, not to be exposed anymore to the future implications. So we have the clear visibility on the leverage, on the cost of financing, and so we adjust, in fact, the level of PPA we are ready to sign to be in the position to deliver the targeted, the double-digit profitability. So... There is no miracle, I would say, with this interest rate increase or this inflation, we will not change the threshold or we will not change the methodology we use to sanction projects. On the opposite, I would say that it could have some positive effects for total energy because, of course, it will clean, I would say, the competition with less companies able to able to enter or to continue development in that field. Great, thanks very much. We have the strong energy, less competition, so it should be profitable for us and positive for us.

The next question is from Bertrand O'Day 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 integrative 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 LNG portfolio, I think it was three or four years ago, and give us now access to 18 million tonnes of OES capacity in Europe. So we have more or less 15% of the global OES capacity in Europe. So it's a huge advantage for our traders to play, in fact, between the arbitrage between the US and Europe. So for sure, it's key in this LNG trading performance. Once again, having a production... I remind you that we are number one energy exporter in the U.S. as well. So we have a strong presence in the U.S. So strong access to U.S. with more than 10 million tons of energy coming from the U.S. So this has the capacity through our shifts to deliver this energy to our European customers thanks to this RIGA's capacity. And, of course, we have, on top of that, other sources of energy in Asia, in the Middle East, and customers in Asia. So, all in all, it's our traders who arbitrate between the different markets. And now, given the price of the energy, each cargo, it represents something like 80, even 100 million dollars for each cargo. So, when you are able to reroute or to arbitrate between the different markets, of course, it's... 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 CTE. Please go ahead.

Hi Jean-Pierre. EU solidarity tax, you mentioned the 1 billion euro figure, but is this still an estimate? What clarity do you have? You're clearly having some negotiations with different governments, so I just wanted to understand where those negotiations stood. And then secondly, the last few weeks we've seen a pretty big 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 they spot gas prices have collapsed?

Okay. So, the EU solidarity tax. So, as you know, we will be impacted by this EU solidarity tax in six countries in Europe. So, it will be France, Germany, Belgium, Luxembourg. So, mainly on our refining activities, plus Denmark and the Netherlands on the ENP activities. So 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 tax, and each country is supposed to adjust or to adapt this frame locally to their own requests. Having said that, we made, because there are uncertainties regarding the rate, the rate that would be used, because the EU just gave minimum tax rates. There are uncertainties regarding the use of carry-loss forward. So there are, and by the way, another certainty regarding the fact that the basis, if it would be 2022 or 2023, because in the text you have 2022 and or 2023. So, having said that, we made, we're engineers, so we made a lot of different calculations with different scenarios, and all in all, the conclusion that this EU solidarity tax should represent something like 1 billion euros. for the full year 2022.

And the EU gas price falling, yes, for sure.

At present time, we see NBP around $20 per million BTU. It was about $50 per million BTU. It was the end of August, I think, So it's a huge drop, in fact, like $20 per minute. It's not ridiculous when you compare the level we had before the crisis. The main results, or the main factor in paying this drop, as you know better than I do, so it's, of course, lower demand in Europe due to the temperature, the high temperature that we have at present time. And so the lower index, of course, in relation with this situation. The tax, the gas, the gas stocks that are almost full, they are full in France, and so they have been replenished over the past months. And a strong competition between EU companies and Chinese companies to attract energy cargoes to Europe. That's On top of that, you have the UK situation with little storage capacity in the UK that creates another subject, in fact, to evacuate the gas coming to the UK to other European countries. 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, but you will have to rebuild the stocks for the winter 2023, and so given the the lack, once again, of EES 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. So that's why we... Shorter, I don't know. It's a matter, once again, of volatility, temperature, consumption, and so on. But middle term, the message we conveyed in New York when we presented our outlooks, we are very supportive, particularly for LNG gas in Europe, for these intrinsic reasons. So the need for Europe to attract LNG cargoes to compensate the lack or the loss of gas type, Russian gas.

Can I just clarify on the solidarity tax, the one billion euro estimate, does that include the tax plus carry-forwards, or is that a gross number before you adopt it?

It depends. We made some calculations depending on anticipation of what the low could be, depending on the countries. Okay. It does not necessarily have a big impact. It depends on the country, it depends on the situation.

Okay, thank you.

The next question is from Lucas Herman with Exxon. Please go ahead.

Yeah, thanks very much and good afternoon, JP. A couple as well of my, 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 length of the portfolio is exposed Because one of the things I think Patrick has made quite clear in New York was that there is uncertainty as to the longevity of the contracts or whether there's sanctioning of the Russian contracts, which for you is an offtake, I think, of 5 million tons per annum. And as a consequence, there seems to be a reluctance to actually hedge those volumes. So 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 increased over the course of the last few months or will increase going into the fourth quarter and therefore you are more exposed to 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 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. But 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. And then, sorry, just going back to Alistair, I'm sorry for the long list, just to be clear, the windfall tax that you're referring to, or the estimate of a billion, is that... 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 UK component, you talked to something nearer to you.

No, no, no. Okay. So perhaps I will clarify this subject first. So there are two different subjects. So is the windfall tax profit in the UK already implemented? Yes. So with the vote on the implementation in July, retroactively to end of May. And so we mentioned in New York that assuming $30, $35 million BTU and BP over the first quarter, it should represent for 2022, so from end of May to end of December, more or less $1 billion. 1 billion euros, okay? So it's for the windfall tax proceeds in the UK. So it's implemented, so there is no doubt, in fact, the only uncertainty is the NDP level and the production on which this tax will be applicable. So 1 billion euros for this subject. End of September, given that we have to record over the third quarter, in fact, more than four months of windfall tax proceeds In the UK, the impact is something like $640 million. Okay? The second subject is the EU solidarity tax. So, at the same time, we have nothing in our accounts because, once again, there is a lot of uncertainty regarding the way this tax will be implemented. And the figure I mentioned is for this solidarity tax. So, $1 billion, we gave exactly the same figure in New York. I remember well because I gave that figure. And so, 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 UK windfall tax. That is supposed to be applicable until 2025. Okay? Great. Thank you. Regarding LNG hedging policy, so our policy is to hedge the following 12 months. So that's what we mentioned already to you many times, but with some exceptions. And so 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. So that's our policy, so a global policy, but with an exception on Russia.

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

Yes, because we have only the two first months of 2022. So the calculation is correct. And in 2023, it will be something like 5 million tons of cells coming from Russia.

Okay, which will stay unhedged. But can you give us any indication, sorry to ask, in terms of the contribution?

No, what we gave very transparently since, once again, the the publication of the registration documents, is the cash that the Russian upstream activity are able to generate. And so you will see that in the Q2 or Q3, it represents more or less $560 million. So for the second quarter, for the third quarter. And it represents the dividends we are able to repatriate in our accounts. So in the Q2, it was Noretec dividends. In the Q3, it was Yamaha dividends.

Okay. All right. I won't push further. Thank you very much. Thank you.

The next question is from Raj Borkataria with RBC. Please go ahead.

Hi there. Actually, I'm going to push a bit further on Lucas's 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 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? And then the second question is just on the LNG portfolio overall. Are you able to disclose what the level of spot sales was in Q3 and what you would expect to have in Q4 as a proportion of the portfolio? Thank you.

So Yamal of Tech. I'm not sure to have fully understood your question. But we gave. So the cash we received, from Russia on our assets. So it's cash received from Novatec or cash received from Yamal. And once again, you have the figure for the Q2, you have the figure for the Q3. And so I gave the indication that Q2 represents Novatec dividends and Q3 represents Yamal dividends. And so it's 350 million dollars, Q2 and 350 dollars more or less the same figure for Q3.

Jean-Pierre, I was thinking more of the off-take side. So you as a total trading business are buying oil-linked volumes and selling unhedged LNG. Is it fair to assume that that cash flow that you generate from that part of the business, there's no restriction on where the cash resides in terms of going straight to the group cash flow statement?

No, there is no sanction. Okay, that's clear. So our duty is to execute the contract. we have, so the contract we have, to sell part of the Yamal energy volumes to Europe or to Asia. By the way, it's what the European authorities are waiting for us. So, no, there is no restriction. Okay, perfect. That's very clear. The part of our global portfolio, the global automation, I already mentioned to you.

Now that's very clear. And then 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 two or three million tons, but they will come back to you with the precise figure.

Thank you very much. Thank you.

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

Thank you. Good morning, Jean-Pierre. Two questions. One, can you talk about the refineries, right? I think that they just restart on Monday for two of the refineries in France. Can you confirm whether that those two refineries right now are shut down or that you'd 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 understand your question. Sorry. Could you repeat?

Sure. I'm referring to the recent refinery strike in France. I think the labor union that we stopped the strike on Monday. Can you confirm whether the facilities are currently run-made or that has been totally shut down on those two granaries?

What I can tell you is that we have a refinery in Normandy that was shut down almost all October month. And we had a second refinery, so in Faisun, so south of Lyon, that was impacted as well by the strikes. So more or less, for October, it's two refineries in France that were impacted by the strikes.

Okay. And can you also tell us whether that's the ending upstream production contract any meaningful explanation for 2023 or 2024?

Sorry, I haven't understood.

So it's about the upstream contract, but what is your question on this contract?

And the any meaningful upstream production contract will expire in 2023 or 2024. You mean the development contract? No, production contract. Like you have couple one contract, couple 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 in 2023? What do you mean by your production contracts? Your operating contracts.

Ah, okay. Honestly, I have nothing in mind because we have... The end of the non-renewable or the Qatar Gas One contract, it was end of last year.

So we have the same on Bangkok in Thailand. So we withdraw from Myanmar just to remind you the main contract that were ended very recently. But 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. Thank you.

And 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.

Good afternoon, Jean-Pierre. A couple of questions from you, please. The first one is on your Casa dos Ventos acquisition in Brazil, announced yesterday. What kind of debt bubbles 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% 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, so yes, we are very clear. Is the guidance given by the board that the information of the guidance will be given to the market at the end of September? The condition, having said that, you're right that Patrick Pouyanné mentioned that 40% is not a limit. So the 45, 40% is the guidance, but there is no limit. In fact, the 40% is not a ceiling. So what could convert us to go beyond that, of course, is if the environment is very, very, at a very, very high level. So 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 brand new acquisitions we announced yesterday, so it's the fact that we will create a joint venture with Casa dos Santos, so in Brazil, so it's the largest renewable energy developer in Brazil. We will have a stake of 34% in that GV, but having an option to acquire an additional 50%, so that will be more or less 50-50 in the coming years in that GV. 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 the front cash payment of $550 million. So I think it's perfectly in line with our objective to have assets able to deliver return equity above 10%. But once again, the comparison with other portfolios, I think in that case it's not very relevant.

Could I squeeze in a quick one? It's nice to see that you guys are putting in a one-month salary bonus for all employees. Could you just give me an idea of what the total amount of that is and if it's been accrued in your 3Q numbers?

Right. We represent more or less 7% of the global salary cost. But it will be capped. So there will be a minimum, but it will be capped at 26%. 1,000 euros per employee. So more or less 7% of the salary costs worldwide.

Great.

Thank you very much. It's not in my Q3 numbers. It will be in my Q4 numbers, of course.

Okay.

Great.

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

Thank you for your data. Just one quick question left, which is around the lag effect on dividends for equity affiliates that you mentioned. Is that something that is meaningful and we should expect the capture in the fourth quarter, the beginning of next year? Any details on that would be helpful.

Thank you. It's obvious that the performance of the industry is particularly linked to the performance in the LNG sector. And so the LNG business is, in the majority of the cases, a company on an equity basis. So that means that, of course, you have on your net operating income the immediate effect of the performance. But in cash flow generated from operations, of course, you have to wait for the dividends. So there are some rules depending on the country, depending on the partnerships. And so you do not have an immediate effect on your cash flow. And so 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. So I cannot answer to you. It depends on the geography. It depends on the business. So it's a timeline between, I would say, around six months, something like that. It depends because in some geographies, you are able to put in place interim dividends to accelerate, in fact, the cash out from the businesses. In some other geographies, you have to wait because there is just one dividend period. So 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 other companies that were going up, labor costs are rising. So I was wondering if you could offer any more color on Upstream costs and the broader operating and sanctioning environment in the Upstreams. My second question is on refining, and specifically if you could give an update on the Loina 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 Loina refinery now able to fully run on non-Russian seaborne crude?

Thanks. No question, patience. Yes, so I confirm my comment that at present time, given that we are not very present in the US shelf, we do not see really inflation in our costs. Of course, still, what are the 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. And at that time, the teams came to the EXPOM asking us to sanction the project with an impact on the steel price around plus 40%, something like that. So at that time, we said no, we are not in a hurry to sanction the project. And so it's a 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 projects. It's not volume over value. But, obviously, at present time, given globally the underinvestment that has been done by all the oil and gas companies since 2015 or 2016, Globally, we do not see a strong inflation, and so we do not anticipate strong inflation in our book in the coming months. Russia, so Loina, yes, so Loina was designed, in fact, to run... Russian crude. So, as you know, and so we were very clear, it was very early in the year, so it was in March, when we published our rule of conduct regarding Russia, that we no longer buy any spot Russian crude to supply a refinery. Of course, Leuna, it was still in 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 we have to find alternatives. And so the alternatives will come from the pipe coming from Poland, in fact. And so 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, we have discussion with the German authorities to make them aware of these difficulties, of this constraint. So we see, at the time, it was feasible to have more or less 800 kiloton of mount per this pipe coming from Palos. We see in the next, in the next future, we continue with this alternative source to supply a line of refineries. Okay. So I think it was the last question. Okay. So thank you very much for your time. And so I will give you rendezvous. I expect 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 in our disconnect.