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Ladies and gentlemen, welcome to the Third Quarter 2022 Results Conference Call. [Operator Instructions] I now hand over to Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.
Thank you. Hello, everyone. Jean-Pierre speaking. We reported solid third quarter results that continued to demonstrate TotalEnergies' ability to effectively leverage the very strong and volatile environment. This success allowed 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 the decline late in the quarter after OPEC+ announced a 2 million per barrel 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 through the roof by increasing geopolitical tensions and the risk of not enough supply during winter period, 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-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 from their record-setting second quarter levels of close to $150 per tonne. 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, 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 third quarter, down 12% from the second quarter mainly due to a lag effect in the dividends received by equity affiliates. Year-to-date, the DACF 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 held by a 0 net debt balance sheet, an accelerated transition for the multi-energy future and an upgraded through-cycle cash flow payout for shareholders of 35% to 40% from 2022. These were the main messages from the strategy and outlook presentation last month. And the third quarter results confirm these messages.
As part of the environment, the effective tax rate of the company increased to 44% in the third 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 U.K. Energy Profits Levy, $0.6 billion impact on the quarter for 4 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 hydrocarbon production was 2.7 million barrels of oil equivalent per day, a 2.5% decrease from the previous quarter, mainly due to planned maintenance, notably at Ichthys, and unplanned downturn at Kashagan, partially offset by the entry into production of Sepia and Atapu and the ramp-up of Mero 1, all these fields being in Brazil.
Year-to-date, OpEx are trending 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 the commodity business, and maintaining a low breakeven 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 allowed us to overcome the quarter-to-quarter 10% decrease in LNG sales that resulted mainly from the Freeport LNG outage and planned 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, 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 start-up of the Seagreen 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 renewables in Brazil yesterday -- it was yesterday.
Net electricity production was 8.8 terawatt hour 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 & Renewables 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 growth 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, throughout 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 margins and a good trading performance comparable to previous quarter. To put this into perspective, over the first 9 months, the Downstream generated 4 point 8 -- sorry, $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 margin 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 9 months of '22, 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 energy. We bought back $5 billion of our shares over the first 9 months and plan to buy back another $2 billion in the fourth 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 1-month salary to all our worldwide employees and a new shareholder return policy announced in September that targets 35% to 40% cash flow payouts. In addition to the regular third interim dividend of EUR 0.69 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 dividends of EUR 1 per share in December of '22.
That concludes my comments, my remarks. And now we can go to the Q&A.
[Operator Instructions] The first question from Irene Himona with Societe Generale.
I had two questions, please. Firstly, you 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 on the balance sheet, please?
Okay. Thank you, Irene. Yes, so the first question regarding working cap, so that's true. We reported $6.7 billion working cap release in the third 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 release 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 cap 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 U.K. mainly.
And on the other side, we have a minus $0.8 billion of various effects on payables and receivable balance. So that was the main driver behind this performance. So 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. 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 cash-out -- a stronger cash-out or reversal of this performance in the fourth quarter, according to the current environment.
So now perhaps your question on impairment. Yes, so we're recording in our accounts a new -- an 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. So that was the main driver behind these impairments. So we are very transparent. So we published in the recession documents specific at least on Russia.
And so at that time, we gave the capital employed in Russia, so close to $14 billion end of last year, so -- and now given all the different impairments we made, so we made, I remind you, $4 billion -- $4.1 billion impairment in the first quarter, mainly on Arctic 2. We made $3 billion or $3.5 billion impairment in Q2, mainly on Novatek's value this semester -- this quarter, sorry, an additional $3.5 billion. So all in all, it represents more or less impairment of $11 billion. So now to answer to that -- to your question, in our accounts, we have capital employed to Russia around $6 billion taken after this -- all these impairments that has been done.
The next question is from Michele Della Vigna with Goldman Sachs.
Thank you 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 Ichthys returning back from scheduled maintenance.
And then my second question is on your GHG emissions, always very helpful to have it on a quarterly basis and ongoing strong delivery, especially in the reduction of Scope 3. But there was a 10% increase in Scope 1 and 2 emissions. My understanding is most of it comes from Europe and the ramp-up of CCGTs and the Downstream refinery. But I was wondering if you could give a bit more visibility on that.
Yes. So perhaps I will start with the second question. So I'll be very clear, so the increase regarding Scope 1 and 2 in Europe is 100% 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 in France in Brittany in Landivisiau beginning of this year, so -- 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.
And 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 LNGs. Because we were able to replicate very good and very high performance for -- on this segment, on this LNG business, despite shutdowns, so despite the loss of Freeport cargoes in particular in the third quarter. So according to the information I have, Freeport is supposed to come back to 100% capacity before November 2022 -- in December of this year. Nigeria, it will be probably next year. And it is -- so the shutdown has been completed, and so it is supposed to come back to normal production in the fourth quarter.
The next question is from Martijn Rats with Morgan Stanley.
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. And then also, I heard you comment on distillate yields -- 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 products, over the next couple of months.
Okay. So the impact on the refinery strike in France, 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, but we benefited from increased margin in our refineries 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 strikes in France over the October month.
Distillate cracks, yes, they are strong. We think that, of course, the ban on Russian petroleum products that will be effective in February '23 will contribute, of course, to maintain these distillate cracks at very high level. It will not be so easy for Europe to compensate the loss of these volumes. So we -- 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 crude, on Russian crude that will be effective in December.
Because you can, of course, reroute crude from over -- from other countries. But 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 in India, it will be perhaps in China or more globally in Asia. So these countries could benefit from discounted crude. But on the opposite, the European refiners will have to pay a premium to attract new groups. So that's the [ balance ] of this ban, I think, implemented at the level of the EU.
The next question is from Christopher Kuplent with Bank of America.
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 figure. So in chemicals, we start seeing but nominally the impact of the possible recession that could happen next year. On our sales at present time, honestly, given the discounts we have in our retail section, we do not see any drop in volume. So we see outlook for next year, for sure, recession should have an impact on this -- on chemicals, should have an impact on gas as well. But too early, I think, to give precise figures.
The next question is from Oswald Clint with Bernstein.
Just back on the LNG side, please, I wonder if you could help us just 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 active buying spot LNG cargoes in the quarter. So was it -- is it a case that you are having some losses on hedged deliveries but offsetting it with new spot cargoes and have been 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?
Okay. So our performance regarding LNG, so I think 2021 definitely marked the start of a new era of performance for this LNG and electricity trading. And so this business segment quarter-after-quarter replicates very strong performance. So of course, we do not give full details, absolute value for our trading business. But I can tell you is that we -- in the third quarter, we replicated -- on the LNG, gas and power replicated the excellent performance of the Q2 2022. In Q2 2022, we replicated the high performance we have in the fourth quarter of 2021. And perhaps you remember that in first quarter of 2022, we announced that we have a very, very high trading performance.
And so we're qualifying this performance as a lower performance of more than $500 million. So having said that, that's true that we had to record in the Q3 results, the impact of the Freeport outage. And so we -- and the loss of cargoes and the fact that, of course, we have to offset hedging losses. But 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, these hedging losses. And so we have the worldwide presence. So we have LNG production in almost all of the main hubs, so in the U.S., in Qatar, in Australia, just to mention.
And of course, we have the LNG coming from Russia as well. And so we have, given this portfolio and given the outlets 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 we -- the solar farm was inaugurated, it was last week, I think, so in Qatar. So it's globally one of the most sizable solar farm worldwide. I think the equivalent of our -- representing 800 megawatts. I do not have, to be honest, the EBITDA. But I will ask my team, and so we can come to you with the figures.
The next question is from Lydia Rainforth with Barclays.
Three questions, if I could. The first one, with the strategy presentation, I think the guidance was for the gearing to year-end to be at 5%. And essentially, you're already there at the end of this quarter, so -- and I appreciate that 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 bigger-picture question in terms of renewables and the [ holding ] side, we also are 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 business and gives an advantage to companies such TotalEnergies?
Yes. So that's true that our gearing 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 per target. And so we will -- as the CFO, I will be more than happy to continue to strengthen my balance sheet and to continue to decrease the gearing. Having said that, in the fourth quarter, given -- 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 on a -- for the full year, taking into account that we will continue our buyback 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 on the -- once again, on the working capital. But I already mentioned that I do not anticipate as well a very strong variation for the working cap as well. So I would say, more or less at the same level as the level we had end of September. So for renewables, 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 the higher interest rate, 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 sanctioned the project, we had a clear view on the CapEx. And so we're looking at the CapEx, at that time, not to be exposed anymore to the future inflation. So we have a 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 a position to deliver the targeted double-digit profitability. So there is no miracle. I would say with these interest rates increase or this inflation, we don't change the threshold or we don't change the method we use to sanction projects. On the opposite, I would say that it would have the 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. We have the sole advantage, less competition. So it should be profitable for us and positive for us.
The next question is from Bertrand Hodee with Kepler.
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 capacities 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 3 or 4 years ago, and give us some access to 18 million tonnes of regas capacity in Europe. So it means that we have more than 50% of the global regas capacity in Europe. So it's a huge advantage to -- for our traders to play, in fact, between -- with the arbitrage between the U.S. and Europe. So for sure, it's key in this LNG trading performance. Once again, being -- having a production contract on the main ops, we have -- I remind you that we are #1 LNG 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 tonnes of LNG coming from the U.S.
So this adds capacity to our ships to deliver this LNG to our European customers, thanks to this regas capacity. And of course, we have, on top of that, overall subsidies of LNG in Asia, in the Middle East and customers in Asia. So all in all, it allows our traders to arbitrage between the different markets. And now given the price of the LNG, each cargo represents something like $80 million, even $100 million, for example. So when we are able 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.
The next question is from Alastair Syme with Citi.
Jean-Pierre, it's EU solidarity tax, you mentioned the EUR 1 billion figure, but is this still an estimate, and what clarity do you have? I mean you're clearly having some negotiations with different governments. So I just wanted to understand where those negotiations stood? And then secondly, in the last few weeks, we've seen a bit of a collapse in spot gas prices in Europe. I know forward markets haven't changed as much. But did you have any perspective on why you think the spot gas prices have collapsed?
Yes. So the EU solidarity tax. So as you know, we'll be impacted by this EU solidarity tax in 6 countries in Europe. So it will be France, Germany, Belgium, Luxembourg. So mainly on our refining activities plus Denmark and the [indiscernible] on the E&P 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 the solidarity tax, and each country is supposed to adjust or to adapt this frame to locally to their own request. Having said that, we made a lot -- because there are uncertainties regarding the rate, the rate that will be used because the EU just gave a minimum tax rate or uncertainties regarding the use of [ carry loss ] forward (sic) [ loss carryforward ]. So there are -- and the way -- another uncertainty regarding the fact that the basis, if it would be 2022 or 2023 because in the text, you have 2022 and over 2023. So having said that, we made -- we are engineers also, 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 EUR 1 billion 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 above $50 per million BTU. It was the end of August, I think. So it's a huge drop, in fact, like $20 per MBtu is not unique to us when you compare the level we had before the crisis. The main reasons or the main factor explaining this drop that you know better than I do, and so it's, of course, lower demand in Europe due to the [indiscernible]. So like [indiscernible] that we had a certain time. And so the lower already mixed, of course, in relation with this situation.
The tax -- the gas -- the gas stocks that are almost full, gasoline in France. And so they have been replenished over the past months. And the strong competition between EU companies and Chinese company to attract energy cargoes to Europe, that created conditions. On top of that, you had the U.K. situation with little storage capacity in the U.K. that create another subject, in fact, to evacuate the gas coming from -- coming to U.K. to other European countries.
Well, having said that, the price will be highly dependent on the temperature, of course, and the final [indiscernible] in Europe. Stocks are full so we anticipate that winter 2022 should not be a big concern for EU, but you will have to release the stocks for the winter 2023. And so given the lag, once again, of regas capacity of Europe to completely compensate the possible fall in Russian gas coming through pipelines, it would be highly supportive to gas prices in Europe at that time.
So that's why we -- short term, I don't know. It's a matter, once again, of volatility, temperature and consumption and so on. But middle term, so it's the message we will convey in New York when we present our outlook. We are very supportive, particularly for LNG, again, in Europe, for this traffic reasons. So the need for Europe to attract LNG cargoes to compensate the lack of the loss of gas pipe -- gas -- Russian gas.
Can I just clarify on the solidarity tax? The EUR 1 billion estimate, does that include the tax loss carryforwards? Or is that a gross number before you had also...
[indiscernible], we made some calculations defending our anticipation of what the law could be, depending on the countries. [indiscernible] a big incentive not necessarily been impacted, depends on country, it depends on the situation.
The next question is from Lucas Herrmann with Exane.
A couple as well, if I might, and maybe some points of clarification on windfall taxes as well. I just wanted to go back to LNG and get some better sense of what the hedging policy is now, and the extent to which the length 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 the longevity of the contracts with -- or whether there's sanctioning of the Russian contracts, which for you is an uptake, I think, 5 million tons per annum. And that 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 in 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 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 for 5 years, but they very clearly remain in when you present data today.
And then sorry, just going back to Alastair. I'm sorry for the long list. Just to be clear, the windfall tax that you're referring to or the estimate of $1 billion, is that prorated when those taxes become applicable? I asked because it's considerably more modest than the number that you indicated again at the Strategy Day, when including the U.K. component, you talked to something near return [indiscernible].
No. No. Okay. Okay. So perhaps I will clarify this subject first. So there are 2 different subjects. So it's the windfall tax profits in the U.K. It's already implemented. So with the vote on the implementation in July retroactively to end of May. And so we mentioned in New York that assuming $35 per MBtu NBP over the first quarter, it should represent for 2022. So from end of May to the end of December, more or less $1 billion or EUR 1 billion, okay? So it was -- we put a deposit in the U.K. So it's implemented. So there is no doubt. In fact, the only uncertainty in the NBP -- NBP level at the production on which this tax will be applicable. So EUR 1 billion or less for this subject. End of September, given that we have to record over the third quarter in fact, more than 4 months of -- with tax profits in the U.K., the impact is something like $640 million, okay?
The second subject is the 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. And the figure I mentioned is for this solidarity tax, so EUR 1 billion or $1 million. We gave exactly the same figure in New York. I remember well because I gave that figure. And of course, there are some discussions or uncertainty regarding when the tax will be payable, once again, the methodology. And -- but it's supposed to be a one-off that's the main difference compared to the U.K. windfall tax that is supposed to be applicable since -- until 2023 -- 2025, sorry, okay? Regarding LNG hedging policy. So the -- our policy is to hedge the following 12 months. So that's what's definitely 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 1 million tons that you said you'd committed to take in 2022. So we might to take it that 6 million tons of LNG coming from Yamal at the present time is unhedged?
Yes. Yamal, because we hedge only the 2 first months of 2022. So the calculation is correct. And in 2023, it will be something like 5 million tons of sales coming from Russia.
Okay, which will stay unhedged. And but can you give us any indication -- please, sorry to ask in terms of the conversation [indiscernible].
No. What we gave very transparently since, once again, the publication of the registration document is the cash that we -- that our 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 will present the dividends, we are able to repatriate in our accounts. So in the Q2, it was Novatek dividends. In the Q3, it was the Yamal dividends.
And the next question is from Biraj Borkhataria with RBC.
Actually, I'm going to push a bit further on Lucas' question. So for the Yamal offtake, can you just confirm whether there's any restrictions on the difference between earnings and cash flow received from that side of the Russian portfolio? I get that within the equity interest of Yamal at a project level, there might be some issues on getting the cash out. But for the offtake side, should we assume the earnings flow straight to the group cash flow?
And then the second question is just on the LNG portfolio overall. Are you able to disclose what the level of spot sales is -- or spot sales was in Q3, and what you would expect to have in Q4 as a proportion of the portfolio?
So Yamal offtake, 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 Novatek 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, this represent Novatek dividends. And Q3 is for the Yamal dividend in Q3. And so a $350 million Q2, and $350 million more or less the same figure for Q3.
Jean-Pierre, I was thinking more of the offtake 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 is -- 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. There is no sanction. So our duty is to execute the contract we have. Some of the contracts we have, to sell part of the Yamal LNG volumes to Europe or to Asia. And by way, it's what the European authority are waiting for. So no, there is no restrictions. With our global portfolio, the global optimization, I already mentioned to you.
No, that's very clear. And then the spot LNG sales?
Honestly, I do not have the figure for the Q3. My colleagues will come back to you. It should represent something like 2 million or 3 million tons, but -- then we'll come back to you with the precise figure.
The next question is from Paul Cheng with Scotiabank.
Three questions. One, can you talk about the refinery strike, why -- I think that they just -- will start in coming days for 2 of your refinery in France. Can you confirm what does that -- those 2 refinery, why now you shut down or that you'd still be able to run? That's the first question.
I'm sorry, but the line is very bad, and I was unable to understand your question. Sorry, could you repeat?
Okay. Sure. I'm referring to the reason refinery strike in France. I think the labor union that will start the strike on Monday. Can you confirm whether the facilities are currently running or that has been totally shut down on those 2 refineries?
What I can tell you is that we have a refinery in Normandy. That was shut down almost all October month. And we have a second refinery, so in [indiscernible] that was impacted as well by the strike. So more or less for October, it's 2 refineries in France that were impacted by the strikes.
Okay. And can you also tell us whether there's any upstream production contract, any meaningful explanation for 2023 or 2024?
Sorry, I haven't understood. So it's about the upstream contracts, but what is your question, on lease contracts?
Any meaningful upstream production contract will expire in 2023 or in 2024?
You mean the development contracts?
No. Consumption contract like you have [indiscernible] contract. [indiscernible] 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 value operation contracts?
Your operating contracts.
Okay. Honestly, I have nothing in mind because we have -- the end of the [indiscernible] non-renewable, the Qatargas 1 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 indeed very recently. But on top of that, in the current month, I do not think it will be -- I have nothing in mind -- I have nothing sizable in mind, no. And by the way, the production is supposed to grow over the next couple of years.
The next question is from Amy Wong with Credit Suisse.
Jean-Pierre, a couple of questions from me, please. The first one is on your Casa dos Ventos acquisition in Brazil announced yesterday. What kind of debt levels sit in 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 you guys go beyond that ceiling?
Yes. So the capital return policy. So yes, we're very clear in the guidance given by the Board, the information of the guidance we gave to the market end of September. The condition -- having said that, you're right that Patrick Pouyanné mentioned that 40% is not the limit. So the 45%, 40% is the guidance, but there is no limit. In fact, the 40% is not a ceiling. So what would commit us to go beyond that? Of course, it's the environment is at a very, very high level. So if you have, at the same time, oil, gas prices, refining margins, petro chem, all our business that is trading, are performing particularly well. That's what I can tell you. On the Brazil acquisition, so we announced yesterday. So it's -- the fact that we will create a joint venture with Casa dos Ventos, so we buy this. 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%, so that to be more or less 50-50 in the coming years in the [indiscernible]. 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 come -- that will be developed in the coming years. All in all, so we pay the front cash payment of $550 million. So I think it's particularly in line with our objectives to have assets able to deliver return on equity above 10%. But once again, the comparison with the other portfolio, I think in that case, it's not very relevant.
Okay. Can 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 the size -- what the total amount of that has been accrued in your 3Q numbers?
Right. It 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 as well to a 6 -- EUR 1,000 per employee. So more or less 7% of the salary costs, worldwide. It's not in my Q3 numbers. It will be in my Q4 numbers, of course.
The next question is from Henri Patricot with UBS.
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.
Well, it's obvious that we -- the performance in the Q3 is particularly linked to the performance in the energy sector. And so the LNG business is in the majority of the [indiscernible] accounting on an equity basis. So that means that, of course, you have, on your net operating income, the immediate effects of the performance. But in cash flow generated from operations, of course, you have to wait for the dividends at all. There are some rules depending on the country, depending on the partnerships. And so it's not -- you do not have an immediate effect on your cash flow, FFO. So yes, there is a time line effect between the increase of impact on the net operating income, and the impact you will have on the cash flow from it. So I cannot answer to you. It depends on the geography, it depends on the business. So it's a time line between, I would say, around 6 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 the sum of [ normalcy ], you have to wait because they are just one dividend value. So it's a mix between the different situations.
The last question is from Kim Fustier with HSBC.
I had 2 questions, please. The first one is that I was intrigued by your comments that you're not seeing cost inflation in upstream other than that coming from higher energy costs. We're hearing from other companies that rates were going up, labor costs, supply chains. So I was wondering if you could offer any more color on upstream costs and the broader operating and sanctioning environment in the upstream. My second question is on refining. And specifically, if you could give an update on the Leuna refinery in Germany that used to be supplied exclusively by Russian pipeline crude. Now that we're a little more than a month away from the start of the EU embargo in December, is the Leuna refinery now able to fully run on non-Russian seaborne crude?
No cost inflation. Yes, so I confirm my comment that at present time, given that we are not very present in the U.S. share, we do not see really inflation in our costs. Of course, still, weather difficulties. I have in mind projects that was presented, I think it was 6 months ago, it was just after the beginning of the war between Ukraine and Russia. And at that time, the teams came to the [indiscernible] with -- 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 projects. And so it's the way we mitigate, in fact, this cost inflation, if in some contracts, we have to face this situation.
We are not in a hurry, so we have to be patient. We have time, in fact, we sanction project as such -- [ volume ready ]. But 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. And so we do not anticipate strong inflation in our books in the coming months. Russia. Yes, so Leuna was designed, in fact, to run a while, to run Russian crude. So as you know, and so we are very clear, it was very early in the year, which 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. And of course, Leuna -- particularly 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 had to import seaborne crudes to compensate the lack of the loss of Russian crude. I will not tell you that it's easy. We are very clear where, of course, we have discussion with German authorities to make them aware of these difficulties, of this concern. So we think -- at present time, it's -- it was feasible to have more or less 800 kiloton of amount per -- despite coming from Poland. We'll see in the next future if we continue with this alternative source to supply the Leuna refinery.
Okay. So I think it was the last question. Okay. So thank you very much for your time. And so 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.