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 on how 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. Jean-Pierre will review the results, and then we'll go to the Q&A. 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. 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 and margins. As Jean-Pierre will show you, our ability to fully leverage the commodity price environment is significantly strengthening our balance sheets and increasing our cash flow to record cash flows for a quarter. 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 continues to reopen, but the threat 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 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 customers. 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 with customers rather than to make ourselves a target for additional taxation in this current environment. Ultimately, energy prices, and we should not forget it, are cyclical, so we do not expect to remain at the top of cycle for the long term. We have been through these type of cycles before, and we are taking a balanced approach to best execute and deliver on our strategy to profitably grow the company through our energy transformation. Our first priority, as you know, is to invest in the company to prepare the future. 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 counter-cyclical opportunities, and this is what we are doing. In the second quarter, we have announced three major new opportunities which will join our portfolio. Our entry into Qatar North Field expansion for LNG. The acquisition of a 50% stake in Clearway, the fifth-largest US 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 2 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 and Rosa. 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 barrels per day capacity, CLOV on Block 17 and Begonia on Block 17/06. The first non-associated gas projects on the fields of Quiluma and Maboqueiro in order to feed Angola LNG plant and deliver more LNG to Europe and Asia. The first solar plant, 45 MW, in partnership with Sonangol. As a result of all these, acceleration of our transition, I would say, we announced it in last April, our first half CapEx were close to $8 billion. We now anticipate that the 2022 CapEx will be in the range of $15 billion-$16 billion, or be 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 2022-2025. The $16 billion, next to $16 billion, is in the range, as I answered to a question during the last call. The QatarEnergy deal will contribute obviously to our future LNG growth. Thanks to this new addition to our portfolio, we maintain our growth ambition in the LNG segment, despite the decision not to invest any more in any new projects in Russia. A word or two on Russia. As you have observed, we implemented our principle of actions announced on March 2022, and we are exiting fully from the oil business, both production and trading, with the recently negotiated exit of the Karachaganak 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 in cash flow. Starting with Investor Day in September, we'll 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 will be 2.3 million barrels per day, but not the global financial performance, nor the return to shareholders growth. 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 we are increasing shareholder return to reflect the current environment and strong cash flow generation. The Board approves the second interim dividend of EUR 0.60 per share, an increase of 5% supported by the underlying 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 of 2021 to the third quarter of 2022, a global amount of 5% of our market cap, which will be bought back through shares. You can deduct from this guidance of $2 billion for the third quarter the same rate but in the second quarter, doubling the rate of the first quarter of buybacks. 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 competing, particularly in light of the dividends we are paying, we never cut. Now, I will leave Jean-Pierre presenting, and he's quite happy, a strong set of results. It will be an easy exercise for him today. 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. We will act accordingly to maximize performance with our strategic ambitions and financial 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. Reported IFRS net income for the second quarter of 2022 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 benefit 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. Net adjusted 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 2022 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 in the first quarter. This is mainly due to higher planned maintenance and production cuts in Nigeria and Libya that were partially offset by the entry into Sépia 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 throughput was 1.6 million barrels per day in the second quarter, and the utilization rate increased to 88%. We target the same high utilization rate 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, three times the level of the same quarter last year. Excellent performance was down $500 million quarter-over-quarter, mainly due to a decrease from the exceptional high contribution from gas, LNG and electricity trading in the first quarter. Adjusted free 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 operations in the second quarter was $4 billion, reflecting a reversal of the margin call and working capital changes in the first quarter. LNG sales were 11.7 million tons in the second quarter, down from 13.3 million tons in the first quarter due to lower spot sales, but 1Q was a record spot sales quarter. The average energy selling price increased to $14 per MMBtu in the second quarter, in line with our guidance, and is expected to increase to more than $15 per MMBtu 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 GW at the end of the second quarter, up 0.9 GW in the quarter, including 0.4 GW related to the start-up or the first phase of the Al Kharsaah solar project in Qatar. Including a pipeline of development projects, our renewable portfolio has grown to more than 15 GW of gross power generation. We are very confident that we can achieve our 2025 growth target of 35 GW. E&P is performing well in this environment and contributed $4.7 billion of adjusted operating income in the second quarter, which correspond 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 impact of sanction 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 liquid 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 two 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 capital changes was $24.9 billion in the first half 2022 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 cost by $4.1 billion to $13 billion at the end of June, so our gearing is below 10%. 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 long run, the reality is that we are using this time to fortify the balance sheet, accelerate the transformation and return value to our shareholders. On that point, I think we are ready for the Q&A with Patrick. The floor is yours. Thank you, ladies and gentlemen. We will now begin the question and answer session. As a reminder, if you wish to ask a question, please press zero one on your telephone keypad and wait for your name to be announced. Please kindly mute any audio source while asking a question. If you wish to cancel your request, please press zero two. Once again, please press zero one if you wish to ask a question. We have the first question from Christyan Malek from JPMorgan. Good afternoon, gentlemen. Thank you for the questions. First question I have is just around your CapEx guide. There 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 gonna think about capital allocation in the medium term, particularly as it pertains to your CapEx profile, both in terms of the absolute level, you know, given you have the absolute right to take advantage of countercyclical investments, but that could come at the risk of an even higher guide going forward. Is it a hard ceiling, is it a soft ceiling? Maybe some sort of clearer line of sight around the medium term and also as it pertains to the mix, given there are, you know, 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, you know, which links back to my question around the CapEx. Just the second question is around demand, and just sort of, you mentioned the sort of recessionary risks, you know, as a result of inflation. Can you elaborate more on what you're seeing, particularly, on sort of a six to 12 month view on the demand dynamics? It does feel as though the sector is being viewed as good as it gets around a risk premia associated with Russia as opposed to anything more structural because demand is clearly not clear in people's minds. Thank you. Okay, thank you, Christyan, for the two questions. First, on the CapEx, you know, in March, we told you, $13 billion-$16 billion, the guidance for 2022-2025. That's true that this year, at the beginning of the year in February, we said $14 billion, $15 billion. We just used 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. You know, as I said, I mean, we have managed to make that deal on the renewables in the U.S. on Clearway. But we have also given instructions to try to accelerate short cycles. I've given several examples of fields in Angola, for example, on Rosa, Girassol, Begonia. It's an opportunity to do it well. To launch these projects 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, you know, in an energy company, in my case, we spend a lot of energy. The energy costs are increasing in the company. I advise the team to accelerate in some programs, CapEx program on energy efficiency, which by the way, is good for our costs, structurally on the long term. It's also good for the emissions, you know. This is another source. 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. It's, I think, the capacity to react to the positive environment. Having said that, I'm keeping it at this stage and will give you more information at the end of September. The idea that the guidance we gave you of $14 billion-$16 billion, for me, is a reasonable guidance for CapEx. That's the point. On the split, that's true, but like you said, you know, we are very happy to have acquired the two oil fields in Brazil of Atapu and Sépia on the Transfer of Rights Surplus farm. There were not many contenders by December. We acquired that on the basis of $60 per barrel, and since beginning of May, we receive almost a share of 40-50,000 barrels per day at $100-$120 per barrel. I can tell you, I'm ready to do other deals like this one, let's be clear, if there are opportunities. I'm afraid when the price of oil is high, that, of course, it's more complex because the expectations might be higher, but so we'll be active. A split of CapEx, at this stage, I'm remaining between my range around, let's say, 50% around oil, 20%-25% around LNG, and 25%-30% around new energies, I think is still valid even if we go up to $16 billion. It's more or less what I 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. I mean, even with the reopening after COVID, you know, we've seen the 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. China is reopening and so you see some, I see some room, positive room for increasing demand for oil. At the same time, there is this question mark that financial markets are nowhere near as strong today. Interest rates are rising. Inflation, inflation is rising again. We could have a risk to see a recession. I mean, I'm not a macroeconomic expert, but this is what I'm reading, including in the US. This could have impact on the demand. We know that when the price remain high, you know, subsidies, in particular in emerging countries are a big burden for governments, and that impacts the demand. You know, you could have some, we've seen a country, I think it's Sri Lanka, but a small country, but other countries could put some policies in order to control the, I would say, the budget burden, which hopefully, which is by subsidizing oil prices, gasoline prices. That could be a negative, I would say. 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. You remember in 2008, when we had a financial crisis, the last huge macro crisis, the impacts on the demand was quite strong, you know? 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, you know? I think OPEC countries are almost at the maximum today. You have Libya, you have Venezuela, but other geopolitical difficulties. You have the U.S. shale oil, where we are not the best expert, but I understand that today, increase of production is facing some shortage of workforces, on rig crews, and so it's not so easy to increase quickly the production. Thank you. Thank you. The next question comes from Irene Himona, Societe Generale. Please go ahead. Thank you. Good afternoon. I had two questions, please. Congratulations on these strong results. Firstly, with the U.K. windfall profits tax in the North Sea, can you say roughly? What you would expect the cost to be for Total? Secondly, in the context of the $16 billion CapEx, aside from the new strategic opportunities which you're exploiting as you accelerate the transition, do you also see inflation starting to creep into the new oil and gas projects and also your renewables, where you're constructing about 5 gigawatts? Thank you. Thank you, Irene, for the two questions. On the second one, no, it's not inflation which is leading the raise of our CapEx guidance to next to $16 billion. It's fundamentally opportunities, short cycles. I cannot tell you inflation is there in our industry. We've seen a few rig rates going up, but we have managed to have access to very acceptable rig rates. I would say on the project side, the only points where we see an increase are raw materials. You know, raw materials like steel, for example. We took the decision recently to postpone the order for steel for a big pipeline in Africa because we consider that it was at the top of the market and better to wait and see some deflation. The raw material part is again 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 with 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. 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 our forecasts, you know. I would say that the U.K. I would say have been always quite in the history they were lowering the tax when the price were low, and they are quite active on the taxation side on both ways, I would say. Lowering when it's low, increasing when it's high. That's the type of elements that we can give you. It will be absorbed in the cash flow that we are generating there in the U.K. Thank you very much. Thank you. The next question comes from Lydia Rainforth from Barclays. Please go ahead. Thank you, and good afternoon, both. Two questions, if I could. The first one, if I can come back to the CapEx side. As you're spending more money and the idea of being able to actually define business, more business models in the low carbon space, are you actually taking more risks? I'm thinking about things a little bit like Clearway or the energy. If so, effectively, how confident should we be about the returns of that additional CapEx? The second one, if I come back to the buyback from the cash return to shareholders. I know, Patrick, you talked about this earlier, but this idea, that balance between how you share the additional CapEx across, or the additional cash flow across stakeholders, be it, the share buybacks, and as you talked about with customers. I'm just trying to get a balance as to over time, how much more can you do in terms of the shareholder returns? Thanks. 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. We know that, and it's an experience we draw from the year 2010, 2015, that if we overspend, I would say the CapEx, then when the low cycle will come back, we have some few difficulties in terms of profitability. We look to the CapEx in a sort of sustainable medium, long-term CapEx. It could vary. This is why we gave you a range, $13 billion-$16 billion. Today we adapt it according to in the range that we gave you, according to the circumstances. I see for shareholders, obviously it's quite valuable that we accelerate short-cycle projects today when the prices are very high. I think it's quite reasonable to behave that way. To maintain, I would say, on the medium, long term, the reasonable level of CapEx. The point is, the buyback is not arbitrated against the CapEx. Let's be clear. The buyback is another question, which is what is the 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 from operations in the first half. If the second half of the year is the same, we'll see it will be $15 billion. It's much higher than the $30 billion-$35 billion we had in mind. 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 transition and also to strengthen the balance sheet. It's possible that by the end of the year, the debt, the net debt will be not far from under 5%. We see that, as I explained to you already, as giving us the opportunity and if the macro environment is changing. You know, when you think about interest rates rising, you could see some valuation of more opportunities coming. It's a matter to be patient. What we don't want to do is just to spend the money quickly, but to keep the capacity to act in order to continue to strengthen our business model. The buyback level, as I told you for the year, we started at $1 billion 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. What we have in mind, if you are adding a sort of burden of, I would say for dividend around $8 billion, it's something around $15 billion, I would say a global return. 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 at 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 already, on this matter. In fact, the low carbon energies today, you know, when you look at fields like biogas, when you have biogas and you sell it at the European gas price, the generation and profitability is quite high, you know. I think the renewable story is fundamentally the return is to, and our business model, as I explained last March, is not to cover all the. Not to cover these renewable projects by regulated prices, you know, which have given you, I would say, a return which could reach 10% after some farm downs, is to keep part of these renewable productions, in order to sell them on the merchant market on the commodity price. 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. This give us some comfort that when you look to these, it's not only renewables, and I'll 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 the electricity trading you can do and valorizing these electrons, again, part of them on the market price, on the spot prices and not only on the guaranteed price, which would limit your dividend. This is for example why recently in the U.K. on the offshore wind farms, 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 guaranteed price because the auction price was around GBP 36, GBP 37, GBP 38 per megawatt hour, and we considered that it was better to do and to keep 30% of our production to valorize this asset in a better way in the future. Thank you. Thank you. The next question comes from Martijn Rats from Morgan Stanley. Please go ahead. Yeah. Hi. Thanks for taking my questions. I've got two. First of all, I briefly wanna ask about the dividends. The dividend is up 5% year-over-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. 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? 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 on what you expect will happen to the European diesel market. 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, and in theory, they should all fall away. In your estimate, are European [audio distortion] 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 two questions. The first one is clear to me. It's not a total one-off, the 5% increase. We told you, if I remember, last September, it's September 2021, but we anticipate a growth of our cash flows by 5% per year for the next five years. In the meantime, there was a Russia hiccup, but as I will explain to you that in September with other opportunities like Qatar, and you are very right as well because we make a share buyback of around 5% of our 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 years, following next years and potentially the next five 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. Thank you for the question to clarify that, and for me, it's a guidance that you can put in your model, 5%. It's really true that, despite Russia, the fact that we bought back 5% of our capital will obviously represent one 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 years after. That's very good point. On diesel, yes, you're right. You know, I think by the way, it's very interesting what is happening today on the European margins. I said to you that they were sky-high during second quarter, and frankly, it was gasoline and diesel which went through the roof. The gasoline spread is beginning to go down, but the diesel one continued to remain high. I think there is a good reason for that, is that fundamentally, you know, 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 gasoline in the past. We made some investments, but not enough to cover the diesel demand. And it's true. That's why I think the spread on diesel is quite high because the market is anticipating some difficulties. That's one of the concerns, by the way, I can tell you, among the governments. Why, for example, the French government signed last week an agreement with Abu Dhabi in order to sort of have a security of 300,000 tons of supply of diesel. By the way, TotalEnergies trading arm will be, I would say, the intermediary between Abu Dhabi and the French state to ensure this supply of diesel. I think the market has that in mind. My view is that the refining margin will not stay at sky-high where we were in the second quarter, will go down. The diesel spread should support in the future these spread. It's necessary because as you know, in a refinery, you spend quite a lot of energy. The cost of energy in our refining has grown up from something like $5 per ton to $20, $25 per ton. All in all, if you want these refineries to continue to be utilized at almost 90% rate, we need to have some support. Otherwise, if because of the cost of energy, refineries will be less utilized. If they are less utilized, you have an impact on the supply to the market. I think there you have a support for these refining margins because of the diesel position, and that's something which we have identified as a key element for in Europe. Thank you. Very clear. The next question is from Lucas Herrmann from BNP. Thanks very much. Patrick, just going back to opportunities that you see and the chance to act opportunistically. The deals that we've seen, certainly in renewable over the course of the last, you know, two, three years have generally been, you know, $1 billion, $2 billion. They've been relatively modest. When you look at the market at the present time, can you see yourself doing something, you know, of significantly greater scale, which I think, given the comments made today is obviously something that, you know, investors are pondering on. That's the first question. The second, just back to Russia and refining Urals. What's the. If within Leuna, I presume that you've been benefiting from, you know, the price that you pay for Urals, given the facility was obliged to run on it. Any idea, can you give us any indication what the benefit has been, but equally, you know, whether the plan to remove Urals from production, you know, remains in place by end of year? I guess it's got to be given it's aligned with sanctions. Thanks, Patrick. 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 multiples, so it's difficult to make some large acquisitions. 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 GIP shareholder point of view, which is our trading capacity to get most of its renewable assets in the U.S. Also we are bringing some potential added value because we can make some corporate PPAs at a large scale because we have also a strong footprint. This is what we are looking for. Making large acquisitions in that field, honestly, we should see before we can do that. 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. Second one on Leuna. Leuna, I'll be clear. We have been very clear. We have begin to stop, by the way, already. One of the contracts which was feeding Leuna from Russia has been stopped, as we announced by March 2022. Today, Leuna is no more supplied only with Russian crude oil. It's a mix of, but it's still some Russian crude oil until December 2022, because the contract will run, and the sanctions will be applied from December 5th, I think, 2022. Obviously, it's clear we'll be on our roadmap. 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. There are discussions today with Germany because you have two refineries, Schwedt and Leuna, which we'd have to share, I would say, with alternative route. That's the position, and the position is clear. That will not fundamentally, I would say, the small benefit we had during these few months is not commensurate with the results of our refining business. Refining business this year has benefited from the refining and chemical segment, has benefited, I would say, first, again, $145 per ton of average margin, frankly, not a shocker. We have never seen that, but it's beginning to decrease. I think we have to be more in the range of $80 than $140. Again, my comments on the crack 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. It's an exceptional performance of oil trading. Two quarters in a row, a little similar to what they've done in the second quarter, 2020. You can consider the $500 million there of super performance of oil trading in these results. Last quarter, it was the gas trading as in power trading. It's true that, you know, in this type of very volatile market, our traders, and we are in a good direction, of course, can make and 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. Your remark on Leuna is right, but again, it does not have a fundamental impact on the results. Thanks, Patrick. The next question is from Biraj Borkhataria from RBC. Hi, thanks for taking my questions. 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? The second question is on your Russian assets and particularly on the LNG side. There was 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? Thank you. Sorry, I didn't catch the second question, Biraj. Sorry. First on NFE, I cannot disclose the terms, but let's be clear, the question was not at all. There was no bonus in that, a very limited bonus in the CapEx, the Qatar deal. The Qatar deal was fundamentally a fiscal bid, I would say, that we had to do. We'll have to pay, of course, the past cost because NFE is a project which have already started, which have been sanctioned by QatarEnergy one year ago, I think. There, of course, we'll have to recover all share of the past costs. There is a small additional bonus, but very limited. This payment will take place when we will close fundamentally the deal. There are, I think, some because, you know, we have some antitrust conditions precedent to follow up. I think, I don't know if it. It's part of the anticipation we have for 2022 or 2023. That, but there is a. It's linked to what I said in my speech. I say, I told you, it will depend on the acquisitions and sales planning. It's part of the uncertainty that we have for this that we, I think we have put into our forecast, the fact that we may have, we will have to pay this past cost of NFE. Second question, the ruble, honestly, I will tell you it would have if it's not the case today. It's not, it's 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 then who, I mean, just a legal, I mean, this question of legal frontier, legal border, if I understand. 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. There is no debate at this stage, but we'll manage that. Okay. Thank you. The next question comes from Bertrand Hodee from Kepler Cheuvreux. Hello. Thank you for taking my question. 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 advantaged 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 is long? 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. The second question is more 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 ton of takers from that project? Wondering if you had already pre-sold or hedged some of those volumes and what kind of negative impact you expect in Q3 from those outages? Thank you. Okay. On the second one, obviously, you know, we had to replace. Missing cargoes. The missing cargoes, because we have some customers somewhere, and we have to ensure the customers. There was two cargoes in the second quarter. We plan eight cargoes missing for the next quarter, 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, they have to give a green light. Of course, we will have to replace these cargoes on the spot market, so it has a cost. You know, I will tell you, it's already taking into account somewhere in our results partially, and 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, large source of production, so up to our LNG teams to manage that. 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. You know, 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 sizable volume of our I would say LNG supplies. Yes, the question of your first answer is positive. Yes, 2023 will benefit from hedges which are put in place, can tell you the policy month after month, on a certain percentage of our portfolio. The first question is positive. The second question is, on the short term, a negative impact, but it has to be absorbed in the global portfolio. Many thanks, Patrick. The next question is from Christopher Kuplent from Bank of America. Thank you. Good afternoon. 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. You know, 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, 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. 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. Thank you. Yes, I will take the question regarding the effective tax rates. In Q2, we are around 40%, 39%, to be precise, over the second quarter. It's in line with the guidance we gave, because this reflects 40%, 47%, 48% for the effective tax rate for E&P. It's close to 50% reflecting the environment above $100 per barrel. It's, for me, 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 a tax rate around 40%, reflecting an E&P tax rate around 40%, 45%. 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 refining margins in relation with our gas and electricity businesses. The balance came from the debit in relation with the tax because of course in the higher environment, we generate more results and of course we will pay tax. We'll pay more tax, but in the coming months. Two main elements b ehind 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 liters per year. You make a guess about the volumes, you multiply by the discount. This is before taxes. Understood. Next question. Thank you. The next question is from Kim Fustier from HSBC. Hi. Good afternoon. Just two 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 Lubmin in Germany? Have you secured any long-term offtake agreements from German gas buyers that help to underpin the project? And how realistic is the start-up date of 1st of December this year? And then secondly, is there anything that you've seen in the final REPowerEU 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? Thank you. On the German project, I think in fact the reality of the project is the following one. There is a German promoter who have identified, I would say the, I don't remember the name of the location, which is next to the Nord Stream 1 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 gas pipeline network of Germany because it's just next to the landing point Nord Stream 1. 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 into the FSRUs and not to feed. We are developing that project. The promoter, the German promoter which has this idea, 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 know, you have. If we bring some LNG in that FSRU, this will be put in the, in the German, we say in the gas market, European gas market. No, the question is no, we don't have a long-term contract for beyond the terminal for customers, German customers. There is no problem to find some LNG to feed that FSRU. You know, we have enough LNG in our portfolio and, if the gas prices in Europe are remaining at the level they are, obviously a priority will be given to this FSRU, to feeding this FSRU with LNG. We don't need, I would say, long-term contract beyond because it's a floating unit. A floating unit, if there is no more market, you can put it elsewhere, you know. It's a question of duration. For me, in the debate, by the way, about three gas terminals in Europe, I'm very comfortable to bring floating unit 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 gas 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 gas terminal than the floating one. It's an opportunistic move, I would say. The question linked to Europe and when in Europe. I think obviously, you know, you have, I mentioned previously, I think in a question, for example, biogas in Europe, it's an obviously very good case where biogas will be encouraged in Europe. If you develop biogas today and you sell it at the gas or natural gas market price, it's quite a good investment, you know. There might be some segments where Europe is located. The main question in Europe for me is a question of, I would say, access to the space and the capacity to develop the projects, acceptability with the neighborhoods, you know, a lot of stakeholders. All right, it's quite slow. I'm listening to political leaders who say we will accelerate, but for the time being, I don't see much acceleration, I would say. Back to question. 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. For me, the future of Europe is a little like Japan, you know. Security of supply will be there. 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. Fundamentally, the fundamental trend for us on the European market for energy prices is, on the medium term, quite elevated in the medium and long term. The next question is from Amy Wong at Credit Suisse. Hi. Good afternoon. Couple of questions from me, please. The first one is on Papua LNG. You've launched a FEED for the upstream facilities and 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. 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 an area that's growing really quickly, but transparency and credibility on this market is a huge topic at the moment. Could you talk a bit about your strategy in the carbon sinks space, please? Thank you. Okay. Papua LNG, of course, it's very coordinated with the operator of PNG LNG with Exxon. You know, if you remember well, Exxon is also a shareholder of Papua LNG. We decided a few years ago that we need to leverage the potential synergies in both. Of course, in the meantime, there was a decision by PNG LNG to postpone their own additional train. That makes things a little more. The three trains became two 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. They are on both sides. By the way, there are a lot of alignment because there is another company from PNG would join Papua LNG, is Santos after the acquisition of Oil Search. When we took together the decision to launch the FEED on the upstream part of Papua LNG, I think these two partners are consistent in their will to also move forward the FEED for PNG LNG. The reality is that on the timeline to reach at the end of production, the upstream part is a little longer than the downstream part in this project. The six-month difference that we see today should be, at the end, both parts will be together in order to take the FID obviously. I see there a goodwill from both parties to converge. On the carbon sinks, 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. Our teams of specialists, we have 20 people working together, have one clear axis, which is that they invest in high value carbon credits. 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 Verra standards for the experts, which we follow very carefully. That's why, by the way, we think that to develop such very credible projects, it takes time. We are dedicating $100 million per year. We are not convinced that we could spend much more because, you know, each project is really a project by itself, involving a lot of stakeholders. If you want more color on it, Amy, I will encourage my IR team to connect you with the Head of Carbon or Nature Based Solutions, Adrien Henry. He could give you all the more details about it if you are interested. I encourage [Renaud] and his team to connect you. But your concern is very well taken into account in the way we invest. Thanks. I'll take you up on that offer. Thank you. Thank you. The next question is from Paul Cheng from Scotiabank. Hey, Patrick. Good afternoon. Two questions. First, I think you have mentioned previously you're trying to or hope for to finalize the first project in Suriname by year-end. Second question, with the rising fear of recession, how does that impact or if they do in terms of your next year planning for budget, balance sheet and capital return to shareholder? Well, Suriname, we are continuing to drill and progressing positively. Good news, always not an easy plan. I think we gave you a meeting point by end of the year, so I'm still there. I don't have more to give you. Our partner has released a lot of data. I'm sure it helps everybody to understand where we are. We find hydrocarbons. Again, it's a question, to be clear, of finding where there is oil, there is gas. 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 reservoirs? There are studies going on, and we'll have a clarity by the end of the year about our potential development plans. Well, you know, the best way to face a recession is to have a strong balance sheet. I will tell you what my lesson that I learned. I faced several crises in 2015, again in 2020. 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 is the best warranty to ensure the return to shareholders, even through a recession. You know, we've done it with COVID. Let's be very clear, we were the only European majors to maintain the dividend through COVID. By the way, because before COVID, end of 2019, all gearing was lower than 15%. We accepted the gearing to go a little above 20%. We are right, because it went down two years after, one year after. That's exactly what I strongly believe as the best protection for return to shareholders through the cycles and through events and recessions, is a very strong balance sheet. I repeat my commitment to you during my 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. Thank you. The next question comes from Henri Patricot from UBS. Yes, everyone, thank you for the update. A couple of questions from me. The first one, just on the Russian impairment of $3.5 billion. I was wondering if you can expand on why that was triggered this quarter, and now you've got to $3.5 billion. And secondly, on the gas prices, we discussed earlier the LNG price, but more broadly for the upstream, is it still fair to use the sensitivity that you used at the beginning of the year, given the diversions and other moving parts like the U.K. windfall tax, etc., should that be different for the second half? Thank you. Russian impairment, let's be clear, it's every quarter we make some impairment [crosstalk] The point is that the first impairments were very clearly, as we said, that the first quarter linked Arctic 2. There was one project on which we are considering, but the capacity to execute the project will be much more complex because of the sanctions. We made that first decision and it was clear. This one, as you read, if you read the press release, we said that we have made a future valuation of our participation and evaluation of our participation as a shareholder of our stake in Novatek. We concluded that we had, according to our accounting rules, we had to make an impairment according to the calculation. It's around $3.5 billion. As you have noticed, by the way, in the annex of the press release, there was a strange story where our capital employed in Russia was going up by $2 billion just because we had to apply at the 30th of June the ruble-euro rate or dollar rate, which was better for Russia than the one on 31st of March. There was a reevaluation of our capital employed, which has been quite funny, to be honest. I know the accounting rules, we have to follow them. At the time where we are gradually lowering our exposure to Russia, I think, we made all these calculations. It's applying the rules. We'll continue, let's be clear. Of course, it's a monitoring. We closely monitor with our auditors and with the board. We closely monitor and, you know, taking all the news that we can. There are many news coming on Russia, so it's our duty to give you quarter after quarter the situation of our Russian assets. As I told you, however, in my speech, and I think it was an important news to the statement for you, we will present to you end of September the strategy of TotalEnergies, putting aside Russia. That is because we have no more growth in Russia, no new projects. 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. The return of shareholders will not be affected by the fact that we put aside Russia in this presentation. We'll explain to you why we think that we can continue, and we have the opportunities of 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. We published the sensitivity in the press release with the same. What has changed is [crosstalk] EUR 3 billion for [crosstalk] Yeah. What has changed is the absolute value, you know. [crosstalk] In the price has changed a lot, and you see the absolute value impact in our results, I would say. As it's going sometimes from $20- $50, down to $30, it's volatile, but it's 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 to you that in September, of course, is higher than before. 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. That has changed also the perspective of TotalEnergies. As we are very well positioned with our portfolio on European gas as a producer in Norway, Denmark, U.K., and also as a LNG regas importer, we will benefit from that for the future years. Thank you. There is no further question. Thank you for your attendance to this call and very interesting questions, 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. Of course, let's be clear, we continue to monitor very carefully board of directors in terms of return and level of return to shareholders. I invite you, of course, to put on your agenda an important date, which is Investor Day on September 28. We'll be in New York, coming back for the first time in several years to a meeting in person together. 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 always. I think it will be an important event, and we are happy to welcome you there. 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, two long years, I can tell you, Jean-Pierre Sbraire is just aspiring to take the plane in two hours to head. Immediately. 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.