TotalEnergies SE (TTE) 2022 Q2 法說會逐字稿

Ladies and gentlemen, welcome to the TotalEnergies Second Quarter and First Half 2022 Results Conference Call. I now hand over to Patrick Pouyanné, CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Gentlemen, please go ahead.

Hello, everyone. Patrick Pouyanné here. I'm happy to join you today for this call to comment our results together with Jean-Pierre. Our TotalEnergies are taking action to take the most out of the very favorable environment for energy companies. I will also comment, of course, the actions we are taking to execute and deliver on our strategy in such an environment. And Jean-Pierre will review the results, and then we'll go to the Q&A.

So of course, the environment is obviously very supportive, the price of oil, the price of European gas, the price of LNG and the refining margins for this quarter. It is the first time in 25 years in the industry that I am observing such an environment where all segments of our company are benefiting at the same time of strong prices or margin. And -- but as Jean-Pierre will show you our ability to fully leverage the commodity price environment is significantly strengthening our balance sheet and increasing our cash flow to record cash flows for the quarter, and we are performing very well and using this opportunity to accelerate our transformation and benefit our shareholders.

TotalEnergies is indeed fundamentally a commodity company, and we recognize that we are high in the commodity price cycle. On the supply side, the global system will struggle over the coming year to develop additional spare production capacity for both oil and LNG, and this implies medium-term support for high prices. On the demand side, global demand is increasing as economies continue to reopen, but the freight is a potential slide into recession because of inflation.

The Russia-Ukraine conflict and sanctions have pushed refining margins for this quarter to the sky during the second quarter. They have been falling sharply, quite sharply in July, but still remain high. This obviously had a strong impact on gasoline prices at the pump for our customers. And in this context, TotalEnergies extended the fuel price reduction program for its entire network in France through the end of the year. We prefer indeed to share the benefit immediately and directly to our customers rather than to make ourselves a target for additional taxation in this current environment.

Ultimately, energy prices, and we should not forget this, are cyclical. So we do not expect to remain at the top of the cycle for the long term. We have been for this type of cycles before, and we're taking a balanced approach to best execute and deliver on our strategy to profitably grow the company for energy transportation.

Our first priority, as you know, is to invest in the company to prepare the future. And in this period of strong cash flow generation, as explained to you in April, the Board is giving priority to accelerating the transformation potentially through countercyclical opportunities, and this is what we are doing. In the second quarter, we have announced 3 major new opportunities, which will join our portfolio: our entry into Qatar giant north fleet expansion for LNG; the acquisition of a 50% stake in Clearway, the fifth largest U.S. player in renewable energy; and a new venture in India in partnership with Adani for green hydrogen production. These investments with new opportunities -- we have managed to have access to these new opportunities in the very good conditions because of the relationships and the strong positions we have developed in key growth areas.

We are also acting opportunistically at a more tactical level by, for example, moving to floating LNG regas terminals to France and possibly Germany, where we are already maximizing our position as the largest LNG regas provider in Europe. We also are accelerating development of short-cycle projects, for example and notably, to increase gas deliveries to the European market from the North Sea, but also on the oil side, for example, in Angola, with several infill wells on Block 17, on Girassol, Angola.

By the way, Angola will be another showcase of our multi-energy strategy as we are just sanctioning many different projects. Two oil projects, each of 30,000 barrel product capacity, CLOV 3 on Block 17 and Begonia on Block 17/06. The first nonassociated gas projects on the fields of Quiluma and Maboqueiro in order to fit Angola LNG plant and deliver more LNG to Europe and Asia and the first solar plant 45 megawatts in partnership with Sonangol.

As a result of all these acceleration of our transition, I would say, like we announced it in last April, our first half CapEx were close to $8 billion. And we now anticipate that the 2022 CapEx will be in the range of $15 billion, $16 billion probably, next to the $16 billion rather than the $15 billion depending on the timing of acquisition and asset sales. I remind you that in March, we gave a guidance of $13 billion, $16 billion for the year '22-'25. So the $16 billion -- next to $16 billion is in the range, as I answered to a question during the last call.

The Qatar LNG deal will contribute obviously to our future LNG growth. And thanks to this new addition to our portfolio, we maintain our growth ambition in the LNG segment despite a decision not to invest any more in any new projects in Russia.

A word on Russia. As you have observed, we implemented our principle of actions announced on March 22. And we are exiting fully from the oil business, both production and trading with the recently negotiated exit of the Kharyaga oil field during the last quarter. TotalEnergies recorded in its second quarter account a new $3.5 billion impairment related to the potential impact of international sanctions on the value of its stake in Novatek. Russia represents about 5% of our capital employed and cash flow and starting with the Investor Day in September. We present our strategic plans for TotalEnergies in future without taking Russia into account. Fundamentally, that will change some volume figures, for example, the production of 2022 would be 2.3 million barrel oil per day, but not the global financial performance nor the return to shareholders. More details will be given to you at the end of September for strategic presentation.

Also, a priority at the level of the Board is that we are increasing shareholder return to reflect the current environment and strong cash flow generation. The Board approved the second interim dividend of $0.60 per share, an increase of 5%, supported by the underlying of structural growth in our cash flow; plus another tranche of share buybacks of $2 billion for the third quarter, which will represent globally since December -- since the fourth quarter 2021 to the third quarter 2022, a global amount of 5% of our market cap, which will be bought back through the share -- through shares. You can deduct from this guidance of $2 billion for the third quarter the same rate but in the second quarter but doubling the rate of the first quarter buyback. But the buyback should reach at least $7 billion for the year 2022, and I can come back on that.

On a relative valuation basis, frankly, on any reasonable basis, by the way, the TotalEnergies share price is companying particularly in light of the dividends we are paying, and we will never cut.

Now I will leave Jean-Pierre presenting, and he is quite happy, a strong set of results. It will be an easy exercise for him today. But let me just remind -- summarize what I just told you. Yes, we are in a clearly very positive and dynamic environment marked by elevated commodity prices. This may persist for the medium term in our view. The company is demonstrating its capacity to leverage such a positive environment in all the indicators, in particular in terms of cash flow generation, and we will act accordingly to maximize performance with our strategic [negotiations] and initial discipline to allocate capital to energy transformation, to return value to shareholders and of course, to maintain a strong balance sheet for the future.

Jean-Pierre, the floor is yours.

Thank you, Patrick. So reported IFRS net income for the second quarter of '22 was $5.7 billion, which takes into account the $3.5 billion impairment that Patrick mentioned. Adjusted net results were $9.8 billion, up 9% from the first quarter. Earnings per share were $3.75, up by more than 10% with the benefits of buybacks. The second quarter and first half results reflect the dramatic increase in oil, gas and LNG prices as well as record refining margins over the second quarter.

Debt additive cash flow was $13.6 billion, an increase of 14% from the first quarter and double the level of the same quarter last year. For the first half, cash flow was $25.6 billion, again doubling the same period last year and strong enough to cover the full year '22 CapEx plus dividends. This illustrates the leverage that TotalEnergies as a low-cost producer has to the strong commodity price environment in terms of free cash flow generation.

Operationally, upstream oil and gas production decreased by 100,000 barrels of oil equivalent per day to 2.7 million in the second quarter from 2.8 million in the first quarter. This is mainly due to higher plant maintenance and production cuts in Nigeria and Libya that were partially offset by the entry into Sepia and Atapu fields in Brazil. We expect planned turnarounds to be about 40,000 barrels per day higher in the third quarter than in the second quarter and production to be stable at the level of the second quarter, thanks to ramp-ups from the new projects. In the downstream oil business, refinery throughputs was 1.6 million barrels per day in the second quarter, and the utilization rate increased to 88%. We target the same high utilization rates for the third quarter.

Looking now at the results by segments. iGRP, Integrated Gas, Renewables & Power is the growth engine of the company. Adjusted net operating income was $2.6 billion in the second quarter, 3x the level of the same quarter last year. Excellent performance [laid out] $500 million quarter-to-quarter mainly due to decrease from the exceptional high contribution from gas, LNG and electricity trading in the first quarter. iGRP cash flow was $2.4 billion in the second quarter compared to $2.6 billion in the first quarter.

Important to point out that cash flow from operation in the second quarter was $4 billion, reflecting a reversal of the margin goal and working capital changes in the first quarter. LNG sales were 11.7 million tonnes in the second quarter, down from 13.3 million tonnes in the first quarter due to lower spot sales, but the 1Q was a record for third quarter. The average energy selling price increased to $14 per MBtu in the second quarter, in line with our guidance and is expected to increase to more than $15 per MBtu in the third quarter, given the evolution of oil and gas prices and the lag effect on price formulas.

Gross installed renewable power generation capacity grew to 11.6 gigawatts at the end of the second quarter, up 0.9 gigawatts in the quarter, including 0.4 gigawatts related to the start-up of the first phase of the Al Kharsaah solar project in Qatar. Including the pipeline of development projects, our renewable portfolio has grown to more than 15 gigawatts of gross power generation. So we are very confident that we can achieve our 2025 growth target of 35 gigawatts.

E&P is performing well in this environment and contributed $4.7 billion of adjusted debt to operating income in the second quarter, which corresponds to return on average capital employed of more than 20% over the past 12 months. This quarter is a bit lower, down 6% from the first quarter mainly due to the lower production and the impact of sanctions on the result of Russian assets. Cash flow was $7.4 billion in the second quarter, slightly above the very strong performance of the first quarter and reflecting the higher liquids price, which was partially offset by lower gas price realization and lower production volumes.

Downstream performed impressively as well, a reminder of the importance of the integrated model, generated $3.2 billion of adjusted net operating income and $3.5 billion of cash flow in the second quarter as it increased refined product volumes to fully capture record high margins in the context of reduced imports of Russian products, plus the exceptional result of trading 2 quarters in a row, $500 million.

At the company level, adjusted net operating income was $18.8 billion for the first half, which represents an annualized return on capital employed of more than 25%. Operating cash flow before working cap changes from $24.9 billion in the first half '22 or more than twice what we generated in the first half of the year.

Our net investment in the first half were $7.8 billion. We are able to reduce net debt costs by $4.1 billion to $13 billion at the end of June, so our gearing is below 10%. And in addition to paying the dividends, we bought back, as Patrick mentioned already, $2 billion of our shares during the second quarter as announced.

The company is financially stronger and operationally performing better than anyone can ever recall. While we do not expect this environment to last for a long run, the reality is that we are using this time to certify the balance sheet, accelerate the transformation and return value to our shareholders.

And on that point, I think we are ready for the Q&A.

So the floor is yours.

(Operator Instructions) We have a first question from Christyan Malek from JPMorgan.

First question I have is just around your CapEx guide. It seems to be sort of a long-term target, which you've clearly reached the top of. Could you provide any guidance around how you're going to think about capital allocation in the medium term, particularly as it pertains to your CapEx profile both in terms of the absolute level given you obviously right to take advantage of countercyclical investments, but that could come at the risk of an even higher guide going forward? So is it a hard ceiling? Is it a soft ceiling? And maybe some line -- sort of clear line of sight around the medium term and also as it pertains to the mix given there are some great opportunities also within oil. Could we see you taking advantage, Patrick, of as you have done so exceptionally of good deals, be it sort of wholesale assets, which links back to my question around the CapEx?

And then just the second question is around demand and just sort of, you mentioned, the sort of recessionary risks as a result of inflation. Can you elaborate more on what you're seeing, particularly sort of a 6- to 12-month view on the demand dynamics? Because it does feel as though the sector is being viewed as good as it gets around the risk premium associated with Russia as opposed to anything more structural because demand is clearly not clear in people's minds.

Thank you, Christyan, for the 2 questions. First, on the CapEx, in March, we told you $13 billion, $16 billion as a guidance for '22-'25, and that's true. But this year, at the beginning of the year in February, we said $14 billion, $15 billion. We just use the guidance we gave you to go to $15 billion, $16 billion, close to $16 billion. Why? Because obviously, as I told in the speech, I think we have decided to accelerate on some opportunities. As you know, as I said, we just I mean, we have managed to make that deal on the renewables in the U.S. on Clearway. But we have also given instruction to try to accelerate short cycles. I have given several examples of sales in Angola, for example, Pazflor, Begonia. So it's an opportunity to do it well. To launch this project before, by the way, cost increase in the industry. So we benefit from a good environment today.

It's also a question I can tell you, we have also given instructions because in an energy company in, like us, we spend a lot of energy. So the energy costs are increasing in the company. So I have asked the team to accelerate in some programs, CapEx program on energy efficiency, which, by the way, is good for costs structurally in the long term. It's also good for the emissions, so this is another source. So I'm very comfortable to see the company in such an environment, to spend this year next to $16 billion rather than the initial $14 billion, $15 billion.

So it's, I think, the capacity to react to the positive environment. Having said that, I'm keeping at this stage, and we'll give you more information in end of September. But the idea that the guidance we gave you at $14 billion, $16 billion for me is a reasonable -- is a reasonable guidance for CapEx at that point.

On the split, that true, but like you said, we are very happy to have acquired the 2 oil fields in Brazil of Atapu and Sepia on the [Petrobras] farm were not many contenders by December. We acquired that on a basis of $60 per barrel. And since beginning of May, we received almost a share of 40,000, 50,000 barrel per day at $100 per barrel. So I can tell you I am ready to do other deals like this one, would be clear if there are opportunities. I'm afraid when the price of oil is high but of course, it's more complex because the expectations might be higher, but -- so we'll be active.

Speaking of CapEx, at this stage, I'm remaining between my range around, let's say, $50 billion around oil, 20%, 25% around LNG and 25%, 30% around new energies, I think, is still valid with -- even if we go up to $16 billion, but it's more or less what you have in mind.

On the demand side, the question is a tricky one. Because on one side, we see no real decrease of demand today with the M&A. I mean even with reopening after COVID, we've seen that jet fuel demand is quite strong. Aviation is coming back and it's not yet at the level of 2019, so there is still room for improvement. We have seen in the last quarter that China was closed, and so the demand in China was weak, but China is reopening. And so I see some room, positive room for increasing demand for oil. At the same time, there is this question mark about financial markets, not so strong today. Interest rates are raising. Inflation is rising again. So we could have a risk to see a recession.

I mean I'm not the macroeconomic expert, but this is what I'm reading, including in the U.S. So this could have impact on the demand. And we know that when the price remain high, subsidies in particular in emerging countries are a big burden for government, and that impacts the demand. You could have some -- we've seen in the country. I think it's Sri Lanka, the small country, but other countries could put some policies in order to control the, I would say, the budget burden, which is by subsidizing oil prices, gasoline prices. So that could be a negative, I would say.

So all in all, I think that I'm positive -- I see some more positive trends on the demand than negative, but there is these macroeconomic risks. And you remember, in 2008 when we had the financial crisis, the last huge macro crisis, the impacts on the demand was quite strong. So that's something.

Having said that, I repeat what I said. I don't see, as well on the supply side, much room for improvement. And I think OPEC countries are almost at the maximum today. You have Libya, you have Venezuela, but overall geopolitical difficulties. And you have the U.S. shareholder, where we are not the best expert, but I understand. But today, increase of production is facing some shortage of workforces on recruits, and so it's not so easy to increase quickly the production.

The next question comes from Irene Himona, Societe Generale.

I had 2 questions, please. And congratulations on the strong results. Firstly, with the U.K. windfall profit tax in the North Sea. Can you say roughly what you would expect the cost to be for Total?

And then secondly, in the context of the $16 billion CapEx aside of the new strategic opportunities, which you are exploiting as you accelerate the transition, do you also see inflation starting to creep in the new oil and gas projects and also your renewables where you're constructing about 5 gigawatts?

Thank you, Irene, for the 2 questions. On the second one, no, it's not inflation, which is leading the raise of our CapEx guidance next to $16 billion. It's fundamentally opportunities, short cycles, but I cannot tell you inflation is there in our industry. We've seen some few rig rates going up, but we have managed to find to have access to very acceptable rig rates.

And I would say on the project side, the only point which where we see an increase are raw materials, raw materials like steel, for example. And we took the decision recently to postpone the order still for a big pipeline in Africa because we consider that it was at the top of the market, and we better to wait and see some deflation. So the raw material part is kind of may have some impact, but it's not the reason why -- it's why we have given you $15 billion, $16 billion next to $16 billion. It's more the results, as you said, of being opportunistic on some M&A activities, which are fitting our strategy and accelerating short-cycle CapEx.

On the U.K. side, the evaluation we have for this year is around $500 million of impact of these taxes. But if you -- I can tell you that -- I would say for me, the cash, by the way, which is generated today with the European gas price on the U.K. operation is also much higher than expected in all of our cash. So it's -- and I would say that the U.K., I would say, have been always quite in the history, they were lowering the tax when the prices were low. And they are quite active on the taxation side in both ways, I would say, a lowering when it's low, increasing when it's high. So that's the type of elements that I can give you, but it will be absorbed in the cash flow that we are generating there in the U.K.

The next question comes from Lydia Rainforth from Barclays.

Two questions if I could. The first one, and if I can come back to the CapEx side, and as you're spending more money and the idea of being able to actually define business models in the low-carbon space, are you actually taking more risk? So I'm thinking about things a little bit like Clearway or the Energia. So effectively how confident should we be about the returns of that additional CapEx?

And then the second one if I come back to the buybacks and the cash return to shareholders. I know, Patrick, you talked this early, but this idea that balance between how you share the additional CapEx on additional cash flow across stakeholders, be it the share buybacks, the -- and the customer. So I'm just trying to get a balance over time how much more can you do in terms of the shareholder returns.

Okay. On the second question, first, let's be clear. The CapEx guidance is, for us, a question of medium- and long-term profitability of our business model. So we know that -- and it's an experience we draw from the year 2010, 2015. But if we overspend, I would say, the CapEx, then we -- when the low cycle will come back, we have some few difficulties in terms of profitability.

So we look to the CapEx in a sort of sustainable medium-, long-term CapEx. So it could vary. This is why we gave you a range of $13 billion, $16 billion. And today -- and so we adapt it according to -- in the range that we gave you according to the circumstances. And again, I see for our shareholders, obviously, it's quite valuable, but we accelerate short-cycle projects today when the price are very high. So I think it's quite reasonable to behave that way. And -- but to maintain, I would say, on the medium and long term, the reasonable level of CapEx.

The point -- so that's -- so the buyback is not arbitrated against the CapEx. Let's make it clear. The buyback is another question, which is what is a global return to shareholders. Of course, when you have a huge -- I mean, I think you can see that we have generated almost $25 billion, I think, of cash flow from operations in the first half. The second half of the year is the same. We'll see. It would be $15 billion. So it's much higher when the $30 billion, $35 billion we had in mind.

So the question for us is, how do we share the, I would say, extra profits. The Board wants to use this opportunity again to accelerate this transition and also to strengthen the balance sheet. So it's possible that by the end of the year, the debt -- the net debt will be not far from under 5%. But we see that, as I explained to you already, as giving us the opportunity if the macro environment is changing. When you think about interest rate raising, you could see some valuation of more opportunities coming. It's a matter to be patient. So what we don't want to do is just to spend the money quickly, but it's to keep the capacity to act in order to continue to strengthen our business model.

So the buyback level, as I told you, for the year, we started at $1 billion for per quarter. We raised to $2 billion. Now I told you that the $2 billion will be maintained. It will be at least $7 billion for the year. In mind, what we have in mind, if you are adding a sort of burden of, I would say, for dividends, around $8 billion, it's something around $15 billion, I would say, of global return. And we'll monitor that according to what will be the results and the cash flow generated for the second half. This is the way we look to all of that.

To come back to your question, the first question, which is low carbon and the returns, I think, again, I repeat what I said you already on this question. And in fact, the low carbon energy is today, when you look to fields like biogas, when you have biogas, and you sell it at the European gas price, the generation and profitability is quite high. And I think the renewables -- sorry, fundamentally, the return is to under our business model, as I explained last March, is not to cover all the -- not to cover these renewable projects by regulated prices, which I've given you, I would say, a return which could reach 10% after some farm downs. It's to keep part of these renewable productions in order to sell them on the merchant market on the commodity price.

And again, if you make the math today with the electricity price we can observe in Europe, you would see that the profitability is much higher than the 10% that we have already put as a minimum target. So this gives us some comfort that when you look to this -- it's not only renewables, and I explain you, it's renewable and electricity value chain. You need to look to the whole value chain and the way to manage not only the renewable production as part of your electricity production and more of the electricity trading you can do.

And by the way, better raising these electrons, again, part of them on the market price on the spot prices and not only on warrantied price, which would limit your dividend. This is, for example, why recently in the U.K. on the offshore wind farm, the Seagreen offshore wind farm, we decided not to apply for a new CFD, a new contract for difference, but to keep 30% of the production on the free market, on the spot market and not to cover the whole production as a warrantied price because the auction price was around GBP 36, GBP 37, GBP 38 per a megawatt hour. And we considered that there was better to do and to keep 30% of our production to valorize these assets in a better way in the future.

The next question comes from Martijn Rats from Morgan Stanley.

I've got 2. First of all, I briefly want to ask about the dividend. The dividend is up 5% year-on-year, but I was wondering if there is a case to be made that we should be starting to see that as a future trend rate of growth rather than just what it is for this year. And the reason for asking is, of course, that the buyback is now sufficiently large to effectively allow the dividend to grow 5% a year just by shrinking the share count. Would you see that 5% more as a trend rate going forward? Or is it still a bit of a sort of one-off, above-trend rate sort of type of hike?

And the other one I wanted to ask perhaps a bit more macro and slightly less related to the company, but you'd be well suited to answer it. So I wanted to ask it, nonetheless. I was hoping you could say a few words of what you expect will happen to the European diesel market, and the reason I'm asking it is that European diesel imports from Russia continue at about 700,000 barrels a day or so. It's about 10% of our European diesel consumption simply comes from Russian imports. And they are all seaborne, they're fully subject to the embargo that kicks in, in February. In theory, they should all fall away. In your estimates, are European suited to ramp up diesel production? Can they do that with less gas being available? Can we import it from somewhere else? It seems there's an awful lot of tension in that market, and I was hoping you could say a few words about it.

Thank you, Martijn, for the 2 questions. The first one is clear to me. It's not at all a one-off, the 5% increase. We told you, if I remember, last September, in September '21, that we anticipate a growth of our cash flows by 5% per year for the next 5 years. In the meantime, there was a Russia hiccup. But as I will explain you that in September with other opportunity like Qatar, and you are very right as well. Because we make a buyback share of around 5% of the capital, I would say, for me, the 5% is a guidance that we are willing to follow not only as a one-off for the next year, following next year and potentially the next 5 years. We have room in our portfolio. This is why we said the growth of dividend must be supported by sustainable underlying CFFO growth, I think. So thank you for the question to clarify that. And for me, it's a guidance that you can put in your model, 5%.

And it's really true that despite Russia, the fact that we bought back 5% of our capital will obviously represent 1 year of 5% increase and this is the intent for me. When you bought back shares, it's somewhere the return to shareholder is effective only if you put it in your dividend the year after. So that's very good point.

On diesel, yes, you're right. I think when you sum up, it's very interesting what is happening today on the European margins. I said to you that we are at the sky during the second quarter. And transit was gasoline and diesel, which went to the roof. The gasoline spread is beginning to go down, but the diesel one continues to remain high. And I think there is a good reason for that. is that fundamentally, our European system does not produce enough diesel fundamentally. Before, they like the gas, in fact, natural gas. The refining system in Europe was mostly designed to produce gathering. In the past, we made some investments, but not enough to cover the diesel demand. So -- and it's true. That's why I think the spread of diesel is quite high because the market is anticipating some difficulties. That's one of the concern by the way, I can tell you, among the government.

So of course, we will -- on our side, we are looking to its win, for example, the French government signed last week an agreement with Abu Dhabi in order to resource security of 300,000 tonnes of supply diesel. And by the way, TotalEnergies trading arm will be the -- I would say, the company will be the intermediate between Abu Dhabi and the French state to ensure this -- the supply of diesel. So there is -- and I think the market has that in mind.

So my view is that the refining margin will not stay at the sky where we were into second quarter will go down, but the diesel spread should support in the future -- this spread. And it's necessary because, as you know, in our refinery, you spent quite a lot of energy. And so the cost of energy and refining has grown up from something like $5 per ton to $20, $25 per tonne. So all in all, if we want diesel refineries to continue to be utilized at almost 90% rate, we need to have some support. Otherwise, because the cost of energy, refineries will be less utilized. And if they are less utilized, you have an impact on the supply to the market. So I think there you have a support for the refining margins because of the diesel position, and that's something that we have identified as a key element for -- in Europe.

The next question is from Lucas Herrmann from BNP Paribas.

Patrick, just going back to opportunities that you see in the chart to act opportunistically. The deals that we've seen certainly in renewable over the course of the last 2, 3 years have generally been $1 billion, $2 billion. They've been relatively modest. So when you look at the market at the present time, can you see yourself doing something of significantly greater scale, which I think given the comments made today is obviously something that investors are pondering on? So that's the first question.

And the second, just back to Russia in refining Urals, what's the -- within Leuna, I presume that you've been benefiting from the price that you paid for yours given the facility was obliged to run on it. Any idea -- can you give us any indication what the benefit has been, but equally, whether the plan to remove Urals from production, remains in place by end of year? I guess it's got to be given it's a line of sanctions.

Again, on the first question, you know my point of view, my point of view is that renewable assets are today valorized at very high -- too high multiple, so it's difficult to make some large acquisitions. I don't want to embark to -- there is no way for me to pay too much for some assets. So it's not -- we have done, like you said, some few deals which were directly negotiated with some companies because they see some added value of having TotalEnergies as a partner.

For example, in the Clearway deal, we managed to do that deal because we are bringing additional value to Clearway from the shareholder, GIP shareholder point of view, which is our trading capacity to get most of this renewable assets in the U.S., but also we are bringing some potential added value because we can make some corporate PPAs at a large scale because we have ourselves a strong footprint. So this is what we are looking for. Making large acquisitions in that field. Honestly, we should see before we can do that, so it will be not as large as you think. We should see a large decrease of the value of these companies we could -- before we could contemplate that.

So second one on Leuna. Leuna, I'll be clear, we have been very clear. We have begun to stop by the way, already one of the contracts, which was feeding Leuna from [Orenburg], has been stopped as we announced by March 22. So today, Leuna not more supplied only with Russian crude oil. So it's a mix of some Russian crude oil until December 2022 because the contract will run and the sanctions will be applied from December 5, I think, 2022. So obviously, and it's clear we will be on our road map. So that means that Leuna will be fed by crude oil coming from the North Sea, probably Ekofisk and others through a network pipeline through Poland. And there are discussions today for Germany because we have 2 refineries RED and Leuna, which I would have to share, I would say, this alternative route. So that's the post better position, and the position is clear.

So -- but again, that will not fundamentally -- I would say the small benefit we had during the few months is not a commensurate with the results of our refining business. The refining business this year has benefited from the -- Refining & Chemicals segment that benefited, I would say, first, again, $145 per ton of average margin, frankly, not a single offer. We have never seen that, but it's beginning to decrease. I think we are today more in the range of $80 and $140. So again, my comments on the gasoline spreads, which are sharply going down.

There is also a benefit. I think it was mentioned by Jean-Pierre in the refining and chemical profit of a very strong performance, I would say an exceptional performance of our oil trading. But 2 quarters in the row, a little similar to what they've done in the second quarter 2020. So you can consider that $500 million there of super performance of our oil trading in these results. Last quarter, it was the gas trading and the power trading. But it's true that in this type of very volatile market, our traders, and we are in a good direction, of course, can make a benefit of these -- of such, I would say, dislocations in the market. I don't know if it will be repeated for the coming quarters because it's a question of volatility. So your remark on Leuna is right. But again, it does not have a fundamental impact on the results.

The next question is from Biraj Borkhataria from RBC.

The first one is on Qatar. Congratulations for being the first major to enter the expansion project. Can you disclose the entry or payment structure for that project? And just confirm whether that's included in the $16 billion CapEx budget?

And then the second question is on your Russian assets and particularly on the LNG side. So there were some articles recently around Gazprom potentially adding LNG to the gas -- rubles for gas scheme. Can you just talk about if that was implemented, how you're thinking about -- how that would impact your operations at Yamal?

Sorry, I didn't catch the second question, Biraj. Sorry. As for being ruble use. Okay, ruble. Okay. Sorry. First, on NFE, I cannot disclose it now, but let's be clear. The question was not at all -- there was no bonus. In fact, a very limited bonus in the CapEx. The Qatar deal was fundamentally a fiscal bid, I would say, that we had to do. So we'll have to pay, of course, the pass cost because NFE is a project which have already started, which have been sanctioned by Qatar Energy 1 year ago, I think. So of course, we'll have to recover all share of the pass costs. There is a small additional bonus but very limited.

And then -- and this payment will take place when we will close fundamentally the deal. So there are, I think, some -- because we have some antitrust conditions precedent to follow-up. So I think I don't know if -- so it's part of the anticipation we have for '22 or '23. So but there is -- it's linked to what I said in my speech. I told you it will depend on the acquisitions and sales planning. It's part of the uncertainty that we have for this -- but I think we have put into our forecast the fact that we may have -- we will have to pay these pass costs of NFE.

Second question, the ruble, honestly, I would tell you it would have -- it's not the case today. It's not still in Europe. By the way, it's linked to the project financing. There are some contracts. We'll apply exactly -- we will behave exactly as the gas pipe buyers are behaving today, which I understand is to have a euro account and a ruble account in the same bank and to match the euro account and the ruble account. The question will be -- I mean just a little -- I mean a question of legal frontier, legal border, if I understand. But I don't see -- I mean for me, today, by the way, the discussion is not there, but I don't see some major impact on that. Having said that, the impact, obviously, is on the project financing because this could have some consequences globally. So there is no debate at this stage but with Leuna management.

The next question comes from Bertrand Hodee from Kepler Cheuvreux.

Two questions related to LNG, please. In H1 2022, you delivered very strong LNG contribution despite having already some hedges in place, especially on your advantage LNG offtake out of the U.S. Can you give us a color about your hedging policies for 2023 in LNG given that your structure -- what I want to try to understand is that if current high spot LNG spot prices are sustained in 2023, can we expect a further improvement on your LNG marketing side? Any color would be helpful.

And the second question is more a very short-term question is, can you quantify the impact of the U.S. Freeport LNG outages in your Q3 operation, your 2.2 million tonne of takers from that project? So wondering if you had already presold or hedged some of those volumes and what kind of negative impact you expect in Q3 from that outages.

Okay. On the second one, obviously, we had to replace the missing cargoes because we have some customers somewhere, so we have to ensure the customers. So we -- if there were 2 cargoes in the second quarter, we planned 8 cargoes missing for the next quarter according. And we don't know exactly. I think Freeport is planning maybe to restart by end of September. We see it's according to, I think, the U.S. authorities obviously have to -- the U.S. authorities have to give a green light.

So of course, we will have to replace these cargoes on the spot market, so it has a cost. But I will tell you it's already taking into account somewhere in our results partially. And it's not -- it will not be again -- we will not use that excuse to tell you that the results in Q3 are lower than in Q2. Our teams have opportunities to offset. We have a very large portfolio, a large source of production. So up to our LNG teams to manage that. And it's part, by the way, of our business model. We are sourcing LNG in 10 different plants, and so we must be able to manage this type of hiccups, which led by the way, to your other questions about hedging policies, because this type of event could happen.

We don't hedge. Obviously, you know our teams are not hedging 100% of our capacity. We don't hedge Yamal for an obvious reason, for example. Because Yamal, we don't know what will be the future. So we are prudent. But we are hedging quite a slightly more volume of our, I would say, LNG supplies. And so yes, the question of your first answer is positive. Yes, 2023 will benefit from hedges, which are put in place, I can't tell you the policy month, but a month on a certain percentage of our portfolio. So the first question is positive. The second question is on the short-term negative impact, but it has to be absorbed in the global portfolio.

The next question is from Christopher Kuplent from Bank of America.

Just a few minor ones, hopefully, to hoover up. I just wanted to ask you whether you can give us a bit more detail how much the impact is in your Q2 results and how much you expect for the full year from offering to your French customers a lower price at the pump. And if you can be explicit in terms of earnings versus working capital on a number of these government-funded rebates, that would be great.

Otherwise, I just wanted to ask, your effective tax rate has remained below 40%. In this environment, obviously, the high contribution from downstream helps. But I wonder what your thoughts are regarding upstream effective taxation, whether that is going to approach 50% sooner or later in this price environment or not?

And lastly, if I may, just a quick one on the net working capital inflows that you've seen in the second quarter. Any indication of how much of that is sustainable or you expect to be reversed in the second half would be fantastic.

Yes, I will take the question regarding the effective tax rate. We're around 40% -- 39% to be precise over the second quarter. So it's in line with the guidance we gave because this reflects 40%, 47%, 48% for effective tax rate for E&P. So it's close to 50%, reflecting the environment above the $100 per barrel. So it's -- for me, it's exactly what we have already said. I can remind you what the guidance we gave for the group at $80 per barrel. We gave for the group tax rate around 40%, reflecting the E&P tax rate around 40%, 45%.

And regarding working cap, yes, we cash in more than $3 billion of working cap during the second quarter. The main driver is what I mentioned in my speech, is that we are able to cash in more than $1 billion coming from margins in relation with our gas and electricity businesses. And the balance came from the debt in relation with the tax because of course, in a higher environment, we generate more results. And of course, we will pay tax -- we'll take -- we'll pay more tax in the coming months. So 2 main elements behind this $3 billion cash in for the second quarter.

On the fuel discount, I can refer to what the economy minister, the French economy minister mentioned to the parliament. He spoke about EUR 500 million impact. We sell 10 billion-liter per year. If you take -- so you make a guess about the volumes and multiplied by the discount. This is before taxes.

The next question is from Kim Fustier from HSBC.

Just 2 questions for me, please. Firstly, could you offer any comments on the sort of discussions you've had with the German government or German corporates on the proposed floating LNG project at Lebanon and Germany? Have you secured any long-term offtake agreements from German gas buyers that help to underpin the project? And how realistic is the startup date to 1st of December this year?

And then secondly, is there anything that you've seen in the final repower EU plan whether that's on wind, solar, hydrogen or biomethane that would encourage Total to make incremental low-carbon investments in Europe that you would not have made otherwise?

On the German projects, I think, in fact, the reality is the project is the following one. There is a German promoter we have identified, I would say, the -- I don't remember the name of the location, which is next to the North Stream One pipeline landing area, and they are proposing this location to bring our FSRU and then to connect. The location is quite good because it's very near connection to the pipe gas network of Germany because it's just next to the landing point 01. It's very easy to accommodate. There is some complexity because the LNG tankers could not come to that harbor. We should have a sort of shuttle system to take the LNG from the LNG tankers to bring in to the FSRUs and not to feed. So we are developing that project.

The promoter, the German promoter, which has designed this project is developing that in connection with the German government to get the authorization. Having said that, I think once you go there, you have -- if we bring some LNG in that FSRUs, this will be put in the German, I would say, in the gas market, European gas markets. So no, the question is no, we don't have a long-term contract for beyond the terminal for customers, German customers. But there is no problem to find some LNG to feed that FSRUs. We have enough LNG in our portfolio. And if the gas prices in Europe are remaining at the level they are, obviously, our priority will be given to the FSRU to feeding vis-a-vis with LNG. So we don't need, I would say, long-term contracts beyond because it's a floating unit. And a floating unit, if there is no more market, you can put it as well. It's a question of duration.

So for me, in the debate, by the way, about the gas terminals in Europe, I'm very comfortable to bring floating units because, again, if the market is moving -- because policymakers wants to change their policy around natural gas, we can move it. If you build an onshore regas terminal, you take a longer commitment, and then it's not exactly from my point of view the same commitment for us to invest onshore regas terminal than the floating one. It's an opportunistic book, I would say.

The question linked to Europe and [ran] in Europe. I think, obviously, you have -- I mentioned previously, I think, in a question for example, biogas in Europe. It's an obvious very good case where biogas will be encouraged in Europe. And if you develop biogas today and you sell it at a gas -- at natural gas market price, it's quite a good investment. And also, there might be some segments where Europe is looking good.

The main question in Europe for me is a question of, I would say, access to the space and capacity to develop the projects, acceptability with the neighborhood, a lot of stakeholders or it's quite low. I'm listening to policy leaders, political leaders, to say we will accelerate. But for the time being, I don't see much acceleration, I would say.

So that's the question. So yes, we will consider Europe. Because Europe, again, fundamentally, it's a continent with a lack of energy. We have a lack of energy, like we see lack of natural gas, lack of diesel, lack of energy. So for me, the future of Europe is a little like Japan. Security of supply will be there, and so the local energies that we can develop in Europe will benefit from a higher price of energy in Europe. That's true for us for natural gas, and that's true as well for electricity because all this transition has quite a CapEx cost whatever it is, nuclear or renewable. And so fundamentally -- the fundamental trend for us in the European market for energy prices is on the medium term, it's quite medium, and long term is elevated prices.

The next question is from Amy Wong from Credit Suisse.

A couple of questions from me, please. The first one is on Papua LNG. You've launched a fee for the upstream facilities, and I understand you have plans to then also move on to the liquefaction facility later this year. My understanding, though, is the operator of PNG LNG has not yet moved. And how much support, if any, are you dependent on PNG LNG also simultaneously looking to modify to incorporate your plans for Papua LNG? So that's my first question.

My second question relates to a couple of smaller transactions you did, but nonetheless important. You've done a couple in the carbon sinks area. I mean that's area that's growing really quickly, but transparency and credibility on this market is a huge topic at the moment. So could you talk a bit about your strategy in the carbon sinks space, please?

Okay. Papua LNG, of course, it's very coordinated with the operator of PNG LNG with Exxon. Actually it remained well. Exxon is also a shareholder of Papua LNG. So we decided a few years ago that we need to leverage the potential synergies both. Of course, in the meantime, there was a decision by PNG LNG to postpone their own additional train. So that makes things a little more -- the free trains became 2 trains for Papua. Today, they are working on what is the best possible scheme in order to be efficient, and we are working closely with them. So they are on both sides.

By the way, there are a lot of alignment because there is another company from PNG who joined Papua LNG. It's Santos after the acquisition of wholesale. So when we took together the decision to launch the feed on the upstream part of Papua, I think these 2 partners are consistent in their will to also move forward the feed for PNG LNG. The reality is that on the, I would say, the, what we say, on the time line to reach at the end of production, the upstream part is a little longer than the downstream part in this project. So the 6-month difference that we see today should be at the end all both parts will be together in order to take the FID, obviously. So I see there a goodwill from both parties to converge.

On the carbon things, yes, we are making some few new steps in Congo, in Gabon, I think also in Peru recently. I can tell you, this is not an easy one because yes, it's true, but we want to take a lot into account the transparency, credibility. So all teams of specialists, we have 20 people working to deliver. They have one clear axis, which is that they invest in high-value carbon credits. And we see -- we attach a lot of importance at our level, but we're not there to make greenwashing. It's really to make these projects sustainable long-term projects. There are some standards. I think the VR standards for the experts, which we follow very carefully.

And so that's why, by the way, we don't -- we think that to develop such very credible projects, it takes time. We have dedicated -- we are dedicating $100 million per year, and we are not convinced that we could spend much more because each project is really a project by itself involving a lot of stakeholders. So if you want more color on it, Amy, I will encourage my IR team to connect you with the head of the carbon natural-based solution arena. I could give you all the -- some more details about it if you are interested. And I encourage Renaud and his team to connect you. But your concern is very well taken into account in the way we invest.

The next question is from Paul Cheng from Scotiabank.

Two questions. First, I think you have mentioned previously, you're trying to hope for -- to finalize the first project insurance named by year-end. Just want to see if there's any update on that.

Second question. With the rising fear of recession, how does that impact or that you do in terms of your next year planning for budget, balance sheet and capital return to shareholders?

Surinam, we are continuing to drill and progressing positively. Good news, always not an easy plan. So again, I think we gave you a meeting point by the end of the year. So I'm still there. I don't have more to give you, and our partner has released a lot of data. I'm not sure it helps to everybody to understand where we are. So we find hydrocarbons. And again, it's a question to be clear of finding -- there is oil, there is gas. And of course, gas, we don't flare. This is obviously a point where how do we valorize the gas. Can we inject it in the reservoir? So there are studies going on. And we'll have clarity by the end of the year, but obviously our potential development plans.

Now the best way to face the recession is to have a strong balance sheet. I would tell you that the -- what my lesson that I learned for -- and I faced several prices in 2015, again in 2020. So to be clear, our company with what we are doing, deleveraging the company gearing is under 10%. We plan to have it under 5%, which we have never been in such a situation within TotalEnergies. For me, it's the best guarantee to ensure the return to shareholders even through a recession, and you know we've done it with COVID to be very clear. We were the only European majors to maintain the dividend through COVID. By the way, before COVID end of 2019, all gearing was lower than 15%. So we accepted the gearing to go a little above 20%, and we are right because it went down 2 years after, 1 year after.

So -- but exactly what I strongly believe is the best protection for return to shareholders through the cycles and through events and recessions is a very strong balance sheet. So my -- I repeat my commitment to you. During my speech, introductory speech, I reminded you that we never cut the dividend since 1991. I can tell you it will be the same if we have a recession coming in 2023.

The next question comes from Henri Patricot from UBS.

A couple of questions for me. The first one, just on the Russian impairment of $3.5 billion. So I was wondering if you can expand on your why that was triggered this quarter, I mean to get to $3.5 billion?

And secondly, on the gas prices, and you discussed earlier, the LNG price, but more broadly for the upstream. Is it still fair to use sensitivity that you used at the beginning of the year given the (technical difficulty) NBP in parts like U.K. windfall tax, et cetera? Should that be different for the second half?

Our impairment, to be clear, it's every quarter, we make some impairment tax. The point is that the first impairments were very clearly, as we said, that the first quarter linked to Arctic 2. So there was one project on which we are considering that the capacity to execute the project will be much more complex because of the sanction. So we made that first decision, and it was clearly well. And this one, as you -- if you read the press release, we said that we have made -- put future valuation of our participation -- an evaluation of our participation as a shareholder of our stake in Novatek. And we concluded that we had -- according to our accounting rules, we had to make an impairment according to the calculation. So it's around $3.5 billion.

As you have noticed, by the way, in the annex of the press release, there was strange story where our capital employed in Russia were going up by $2 billion just because we had to apply the 30th of June the ruble, euro rate or dollar rate, which were better for Russia than the one on 31st of March. There was a reevaluation of our capital label, which have been quite funny, to be honest. I know the accounting rules, we have to follow them. But at the time where we want to clearly are gradually lowering our exposure to Russia. I think we made all these calculations.

So it's -- [at the end its] the rules. And we'll continue, let's be clear. Of course, it's monitoring. We closely monitor with our auditors and with the Board. We closely monitor. And you know taking all the news that we can, and there are many news coming on Russia, so it's our duty to review quarter after quarter the situation of our Russian assets. As I told you, however, in our speech, in my speech, and I think it was an important news today statement for you. We will present to you end of September the strategy of TotalEnergies putting aside Russia so -- because we had no more growth in Russia, no new projects. So we want you to consider the future of TotalEnergies without Russia. What means that, as I said, there will be a volume impact but not really any financial impact on performance, and the return of shareholders will not be affected by the fact that we put aside Russia in this presentation, and we will explain you why. We think that we can continue and we have the opportunities or portfolio to continue to see the future of TotalEnergies even putting aside Russia from our perspective.

On the gas price, the answer, Jean-Pierre. I don't think it changed.

No, nothing changed, and we publish responsibility in the press release. It's the same.

What has changed is -- what has changed the absolute value. That has changed a lot. And you see the absolute value impact in our results, I would say. And as it going sometimes from $20 to $50 down to $30. It's volatile, but it's a volatile for good. What is changing as well, I can tell you, is that our long-term assumption on European gas price, and we will explain you that in September. Of course, it's higher than before because with Russian gas out of the European system, that means that fundamentally, European gas price is driven by the LNG price from the U.S., I would say. So that has changed also the perspective of TotalEnergies. And as we are very well positioned with our portfolio on European gas as a producer in Norway, Denmark, U.K. And also as LNG regas importer, we will benefit from that for the future years.

There is no further question.

So thank you for your attendance of this call and very interesting question, which I think will help you to understand and better understand how TotalEnergies can continue to deliver strong results and strong return to our shareholders, whatever the cycle, high, low is. And of course, let's be clear, we continue to monitor that very carefully Board of Directors in terms of return and level of return to shareholders.

And I invite you, of course, to put on your agenda, an important date, which is the Investor Day on September 28. We'll be in New York coming back to, for the first time in several years to a meeting and presence together, and I hope you will be able to join us from both sides of the Atlantic on the U.S. or in the European continent there in New York. Everything will be done to be sure that your health is well taken into account like all, but I think it will be an important event, and we are happy to welcome you back.

Thank you. I wish you a very good summer vacation. Maybe some of you are already in vacation, but you were nice to attend the call for us after a long -- 2 long years. I can tell you, Jean-Pierre is just aspiring to take the plane in 2 hours to...

Immediately.

Immediately. But thank you for your attendance and for your support.

Thank you.

Thank you. Ladies and gentlemen, this concludes the conference call. Thank you all for your participation. You may now disconnect.